UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

(Mark One)

For the fiscal year ended December 31, 2015

OR

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)

 

 

 

One Shell Plaza, 910 Louisiana Street, Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code: (713) 241-6161

Securities registered pursuant to Section 12(b) of the Act:

 

 

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

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 30, 2015, was $2,447.3 million, based on the closing price of such units of $45.65 as reported on the New York Stock Exchange on such date. The registrant had 84,367,376 common units and 67,475,068 subordinated units outstanding as of February 26, 2016.

Documents incorporated by reference:

None

 

 

 

 

 

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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 or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

 

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GLOSSARY OF TERMS

Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

Bbl: Barrel.

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.

kbpd: Thousand barrels per day.

Life-of-lease 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.  

PHMSA: Pipeline and Hazardous Materials Safety Administration.

Product 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.

 

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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.

Tension-leg platform: A vertically moored floating structure normally used for the offshore production of oil or gas, and particularly suited for water depths greater than 300 meters. The platform is permanently moored by means of tethers or tendons grouped at each of the structure’s corners. A group of tethers is called a tension leg. A feature of the design of the tethers is that they have relatively high axial stiffness (low elasticity), such that vertical motion of the platform is significantly reduced. Tension-leg platforms equipped with a drilling rig have direct vertical access for drilling and completing wells, as well as intervention operations.

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.

 

 

 

 

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SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS

 

 

 

 

 

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PART I

 

 

Unless the context otherwise requires, references in this report to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” or similar expressions for time period from and after November 3, 2014, the closing date of our Initial Public Offering (“IPO”), refer to Shell Midstream Partners, L.P. and its subsidiaries, including, for the period from and after October 1, 2015, the Shell Auger and Lockport Operations.  Our predecessor refers to our operations prior to the IPO. Specifically, our predecessor for accounting purposes (“Predecessor”) comprises the following:

 

provided, however, the financial results of Ho-Ho and Zydeco have been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

We refer to the Shell Auger and Lockport Operations for the period from November 3, 2014 through September 30, 2015 as “the Shell Auger and Lockport Predecessor.” We refer to our Predecessor and the Shell Auger and Lockport Predecessor collectively as our “Predecessors.”

The term “our Parent” refers to SPLC, any entity that wholly owns SPLC, including Shell Oil Company and Royal Dutch Shell plc (“RDS” or “Shell”), and any entity that is wholly owned by SPLC or Shell, excluding the Partnership.

References to “our general partner” refer to Shell Midstream Partners GP LLC, a wholly owned subsidiary of Shell Pipeline Company LP (“SPLC”).  References to “Shell” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner.

 

 

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, operate, develop and acquire pipelines and other midstream assets. On November 3, 2014, we completed our IPO. Our common units are traded on the New York Stock Exchange (“NYSE”) under the symbol “SHLX.” As of December 31, 2015, SPLC, through Shell Midstream LP Holdings LLC, owned 21,475,068 common units and 67,475,068 subordinated units, representing a 57.4% limited partner interest in us.  SPLC also owned a 100.0% interest in Shell Midstream Partners GP LLC, our general partner, which in turn owned 3,098,825 general partner units, representing a 2.0% general partner interest in us.

We are a fee-based, growth-oriented master limited partnership. Our assets consist of interests in entities that own crude oil and refined products pipelines and a crude tank storage and terminal system.  Our pipelines and crude tank storage and terminal system serve as key infrastructure to transport and store onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and to deliver refined products from Gulf Coast markets to major demand centers. We generate the majority of our revenue under long-term agreements by charging fees for the transportation or storage of crude oil and refined products through our pipelines and crude tank storage and terminal system.  We do not engage in the marketing and trading of any commodities.  Our operations comprise one reportable segment containing our portfolio of pipelines and other midstream assets.  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.

As part of our IPO, we acquired a 43.0% interest in Zydeco Pipeline Company LLC (“Zydeco”), a 28.6% interest in Mars Oil Pipeline Company (“Mars”), a 49% interest in Bengal Pipeline Company LLC (“Bengal”) and a 1.612% interest in Colonial Pipeline Company (“Colonial”).  

In 2015, we completed three additional acquisitions from Shell with an aggregate purchase price of $1,188.0 million. These acquisitions are as follows:

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As of December 31, 2015, we owned a 62.5% interest in Zydeco, a 28.6% interest in Mars, a 49.0% interest in Bengal, a 3.0% interest in Colonial, a 36.0% interest in Poseidon and a 100.0% interest in Pecten.  See our organizational structure presented by the diagram on the following page.

We own interests in four crude oil pipeline systems, two refined products systems and a crude tank storage and terminal system. The crude oil pipeline systems, which are held by Zydeco, Mars, Poseidon and Pecten, are strategically located along the Texas and Louisiana Gulf Coast and in the Gulf of Mexico. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal and Colonial, connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York. The crude tank storage and terminal system, Lockport, is located southwest of Chicago and receives Canadian crude from the Enbridge pipeline and serves as a distribution point for movements originating on the Mustang and Westshore pipeline systems.

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Organizational Structure

 

Note: Pecten holds 100.0% of the Shell Auger and Lockport Operations.

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Business Strategies

Our primary business objectives are to generate stable and predictable cash flows and increase our quarterly cash distribution per unit over time through safe and reliable operation of our assets and by pursuing strategic acquisitions from Shell and third parties.

Competitive Strengths

We believe that we are well positioned to execute our business strategies based on the following competitive strengths:

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Execution of our strategies and leverage of our strengths are subject to risks and uncertainties.  We may not be successful in executing our strategies.  See Risks Related to Our Business in Part I, Item 1A. Risk Factors of this report.

Our Assets and Operations

Our assets consist of the following systems:

 

⁽¹⁾ We do not own these pipelines that connect to our Lockport terminal.

Zydeco System

General. Zydeco was formed by SPLC in January 2014 to own what was then called the Ho-Ho Pipeline (now called Zydeco, the Zydeco Pipeline or the Zydeco pipeline system). Zydeco’s assets are situated within the largest refining market in the United States. Following the flow reversal project completed in December 2013, the Zydeco pipeline system provides a critical outlet to alleviate current transportation bottlenecks for crude oil produced in multiple basins throughout North America, a large portion of which is transported to and stored in the Houston area, to access major refining centers along the Gulf Coast.

Zydeco spans over 350 miles and currently has a mainline capacity of approximately 375 kbpd. Zydeco consists of four main segments: (i) the Houston, Texas to Port Neches, Texas segment, which has a capacity of 250 kbpd, (ii) the Port Neches, Texas to Houma, Louisiana segment which has a capacity of 360 kbpd, (iii) the Houma, Louisiana to Clovelly, Louisiana segment, which has a capacity of 400 kbpd, and (iv) the Houma, Louisiana to St. James, Louisiana segment, which has a capacity of 260 kbpd. The capacity

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increases facilitate additional crude oil volumes coming into Zydeco at those locations. Zydeco also includes tankage in Port Neches, Texas and Erath and Houma, Louisiana, a dock in Houma, Louisiana and a 16-inch pipeline that indirectly connects to the offshore Boxer pipeline system.  

Ownership and Operatorship. Zydeco wholly owns the Zydeco pipeline system and we own a 62.5% interest in Zydeco. SPLC owns the remaining 37.5% interest in Zydeco. SPLC’s employees operate Zydeco.

Customers. Zydeco’s customers include traders, marketers, refiners and producers. An affiliate of Shell is a customer of Zydeco. For 2015 and 2014, four third-party customers accounted for 75.0% and 66.0%, respectively, of total Zydeco revenue.

Contracts. Zydeco is supported by FERC-approved transportation services agreements and spot volumes.  When the Zydeco expansion projects described below are completed, 86.9% of Zydeco’s fully-expanded mainline capacity will be subject to FERC-approved transportation services agreements with a weighted average remaining term of approximately seven years. The FERC limits contracting to 90% of capacity in order to preserve space for spot volumes, and we believe that Zydeco is well positioned to capture spot volumes with over 60 approved shippers, over 15 delivery points serving major Gulf Coast refineries and access to storage facilities.

Shipping Rates. Zydeco is regulated by the FERC, with shipping rates that may be adjusted annually in accordance with the FERC index. Such regulation allows for annual cash flow increases without commensurate incremental capital expenditures. Contract transportation tariffs range from $1.05/bbl to $2.17/bbl depending on the origin and destination selected for the contract, level of service and contract duration.  Published tariff rates on Zydeco are available on the Federal Energy Regulatory Commission website.

Reversal and Expansion of Zydeco. Demand for new crude oil production in North America has created opportunities for Zydeco. A flow reversal of the Zydeco pipeline system was completed in December 2013. Zydeco now runs from Houston, Texas to market hubs in St. James and Clovelly, Louisiana and transports light crude oil volumes arriving in the Houston market from the Eagle Ford shale, the Permian Basin and the Bakken shale to Gulf Coast refining centers. We completed expansion projects on Zydeco, including the installation of new pump stations and the addition of a new connection at Nederland in 2014. We added new tankage at Port Neches and expect to add a new third-party connection before the end of 2016.

Mars System

General. The Mars pipeline system is a major corridor pipeline servicing a high-growth area of the Gulf of Mexico, originating approximately 95 miles offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana. Mars was initially constructed in 1995, and in 2014 underwent a major expansion. The Mars pipeline system is approximately 163 miles in length and has 16-, 18- and 24-inch diameter lines with mainline capacity of up to 600 kbpd. Mars delivers production received from the Mississippi Canyon area, including the Olympus and Mars A platform and the Medusa and Ursa pipelines, and from the Green Canyon and Walker Ridge areas via the Amberjack pipeline connection, to shore. Due to Mars’ existing connections to the Amberjack pipeline, Mars has benefitted from Amberjack’s recent connections to the Jack/St. Malo, Coelacanth and Powerball fields and future connection to the Big Foot and Stampede fields. Mars is expected to be an increasingly important conduit for crude oil produced in the deepwater Gulf of Mexico to access salt dome caverns in Clovelly, Louisiana, which is a major trading hub. Mars leases its main storage cavern at Clovelly from LOOP LLC, an affiliate of Shell. The cavern lease has been renewed through 2021 and will renew automatically in five-year terms thereafter through 2031, subject to Mars’ right to terminate one year before lease renewal. LOOP LLC may also cancel the lease under certain extraordinary circumstances including the revocation of a governmental license to operate the cavern.

Ownership and Operatorship. We own a 28.6% interest and SPLC owns a 42.9% ownership interest in Mars. An affiliate of BP p.l.c. (“BP”) owns the remaining 28.5% interest in Mars. SPLC operates the Mars pipeline.

Customers. Mars has maintained a set of well-established customers, including an affiliate of Shell. Mars is connected to production platforms and the Ursa and Medusa pipeline systems tie in to Mars, bringing the production from additional production platforms dedicated to these two pipelines into Mars. Mars also receives significant volume from Amberjack at Fourchon, Louisiana, the terminus of the Amberjack pipeline system.

Contracts. For 2015 and 2014, 57.0% and 68.6%, respectively, of volumes transported on Mars were moved either under life-of-lease agreements or posted tariffs from production areas where there was established and consistent production activity and where there was limited take-away capacity beyond what our pipelines offered. Mars tariffs are subject to annual adjustment based on the FERC index. Such tariff adjustments allow for annual cash flow increases without commensurate incremental capital expenditures. In addition, in connection with the expansion described below, Mars entered into life-of-lease transportation agreements with certain producers that include a guaranteed return for Mars for an initial period of time and thereafter will continue for the life of the lease. Mars also moves significant volumes from its connection with the Amberjack pipeline. This connection is governed by a FERC tariff,

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and we expect Mars’ share of the volumes moving under the connecting tariff to grow as production from the new Jack/St. Malo and other fields, connecting to the Amberjack pipeline, increases.

Mars Expansion. Mars completed an expansion project that became operational in February 2014. The expansion added approximately 41 miles of 16- to 18-inch diameter pipeline that connects the new Olympus platform to Mars’ existing pipeline at the West Delta 143 platform. The Olympus platform, which is the largest tension-leg platform in the Gulf of Mexico, accesses the deepwater South Deimos, West Boreas and Mars fields.

Bengal System

General. We own a 49.0% interest and SPLC directly owns a 1.0% interest in Bengal, a joint venture formed by Colonial and SPLC in 2006. Bengal owns a refined products pipeline system connecting four refineries in southern Louisiana to long-haul transportation pipelines. The 158-mile Bengal pipeline system consists of two primary pipelines:

Bengal’s approximately four million barrels of tankage in Baton Rouge connects to the Colonial pipeline and gives customers access to markets in the southeastern and eastern United States.

Ownership and Operatorship. We own a 49.0% interest in Bengal, SPLC owns a 1.0% ownership interest in Bengal and Colonial owns a 50.0% interest in Bengal. Colonial is the system operator for regulatory reporting purposes and operates Bengal’s tankage. SPLC operates Bengal’s pipelines.

Customers. 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.

Contracts. Bengal’s revenue is primarily dependent on ship-or-pay contracts. As of December 31, 2015, approximately 67.0% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts. These contracts are renewable at the election of the shipper. For the ship-or-pay contracts, one of three contracts was recently re-committed to Bengal with a five-year extension, representing approximately 58.0% of total volumes. Rates for Bengal’s transportation services are governed by Bengal’s FERC-approved tariffs. These tariffs are subject to annual adjustment based on the FERC index.

Bengal also has a joint tariff division agreement with Colonial covering transportation of refined products from refineries connected to the Bengal pipeline system to destinations in the southeast and eastern United States via the Colonial pipeline system. Under this joint tariff, Colonial bills and collects the tariff from the product shippers and remits to Bengal its share of the joint tariff.

Poseidon System

General. The Poseidon pipeline system is a 367-mile Gulf of Mexico offshore crude oil pipeline with a 350 kbpd capacity transporting to key markets in Texas and Louisiana. A key corridor pipeline, Poseidon connects to approximately 50 Gulf of Mexico fields and delivers to three locations. It provides access to major crude trading hubs via connecting carriers (i.e., Gibson/Houma to St James and Clovelly, Louisiana and via Cameron Highway Oil Pipeline System to Texas hubs in Texas City and Port Arthur). Poseidon delivers crude oil at the following locations:

Poseidon has ownership of the strategic platform South Marsh Island 205A. Poseidon is expected to enjoy growth prospects driven by new Gulf of Mexico fields in proximity to the pipeline.

Ownership and Operatorship. Poseidon is currently owned 64.0% by the operator, and 36.0% by us.

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Customers. Poseidon’s largest customers are major oil producers who ship from a variety of production fields in the Gulf of Mexico. Each accounts for material throughput on the system, and together these shippers account for 90.0% of the throughput.

Contracts. Poseidon earns income through buy/sell arrangements, pursuant to which it purchases crude oil from its customer at the time the crude oil enters its pipeline system, and then resells the crude oil to the customer at the time the crude oil reaches its destination. At the resell point, Poseidon receives the original purchase price plus an agreed differential (referred to as the buy/sell differential). Many of Poseidon’s customers have dedicated production to the pipeline. Some of Poseidon’s customers have agreed to pay for the transportation of minimum periodic volumes whether or not they actually deliver those volumes for transportation.

Colonial System

General. Colonial is the largest refined products pipeline in the United States based on barrel-miles transported. Colonial includes more than 5,500 miles of pipeline connecting refineries along the Gulf Coast to approximately 265 marketing terminals between Houston, Texas and Linden, New Jersey. Colonial transports more than 100.0 million gallons a day of gasoline, jet fuel, kerosene, home heating oil, diesel fuel and national defense fuels to shipper terminals in 13 states and the District of Columbia.

Ownership and Operatorship. We own a 3.0% interest and SPLC owns a 13.12% interest in Colonial. 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 in Colonial. Colonial operates its pipeline system and has its own management team based in Alpharetta, Georgia.

Customers. Since its inception in 1963, Colonial has served a diverse set of customers, including refiners, marketers, airports and airlines. In 2015, more than 100 shippers transported product through Colonial’s system, including an affiliate of Shell.

Contracts. Colonial is subject to FERC regulation, with both market-based rates and rates that are subject to annual adjustment based on the FERC index.

Auger System

General. Auger is a 174-mile offshore Gulf of Mexico corridor pipeline that transports medium sour crude from producers in eastern Garden Bank and Keathley Canyon blocks. Auger is located near the Lower Tertiary region of the Gulf of Mexico, a developing high growth region.   Auger offers two crude market options: (i) the 20-inch delivers to Ship Shoal pipeline at SS 28 for delivery to the St James market hub (Bonito Sour crude), and (ii) the 12-inch delivers to Eugene Island pipeline for delivery to the Houma market hub (Eugene Island crude). Auger shares a complementary strategic connection to the Poseidon pipeline system through South Marsh Island 205 which provides the producers connected to Southeast Keathley Canyon Pipeline Company L.L.C. (“SEKCo”) the option of either Poseidon or Auger delivery markets.

Ownership and Operatorship. Pecten wholly owns the Auger crude pipeline system and we own a 100.0% interest in Pecten. SPLC’s employees operate Auger.

Customers. Auger provides transportation for major oil producers and from more than 13 different production fields in the Gulf of Mexico.  Auger has several direct connected producers, including the Shell operated Garden Banks 426 (Auger) and Garden Banks 128 (Enchilada) platforms, and the ConocoPhillips operated Garden Banks 783 platform, connected via the Magnolia lateral pipeline.  Auger also receives production from producers connected to Poseidon and SEKCo, including the Anadarko operated KC 875 platform (Lucius), via the South Marsh Island 205 Poseidon pipeline connection.  The Auger pipeline system provides transportation for a number of customers from offshore to St. James via Ship Shoal and Houma via Eugene Island.

Contracts. Auger receives the majority of its revenues from volumes transported on posted transportation rates, some of which are indexed annually.  For direct connected producers, including Garden Banks 426 and Garden Banks 128 platforms, Auger captures transportation revenue for 100.0% of those volumes.  Auger also receives transportation revenue from receipts at the South Marsh Island 205 connection, as producers seek to deliver into the typically advantaged Bonito Sour market at St. James.

Lockport Terminal

General. Lockport is a crude terminal facility located southwest of Chicago with 2 million barrels of storage capacity that feeds regional refineries, while also offering strategic trading opportunities. Lockport receives Canadian crude from the Enbridge pipeline and serves as a distribution point for movements originating on the Mustang and Westshore pipeline systems.

Ownership and Operatorship. Pecten wholly owns the Lockport crude tank storage and terminal system and we own a 100.0% interest in Pecten. SPLC’s employees operate Lockport.

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Customers. The Lockport crude tank storage and terminal system provides storage services for a number of customers,  receives primarily Canadian and Midwest crude and supplies Midwest refineries, such as Citgo Lamont Refinery and via connection to Patoka, a regional distribution hub.

Contracts. Lockport receives its revenues from contracted storage capacity. Lockport has a strong customer base with a track record of more than 20 years, and 100.0% of the leased capacity is being utilized by our customers.

Pipeline Systems and Terminal Systems

The following table sets forth certain information regarding our pipeline and terminal systems:

 

 

⁽¹⁾ MMbls = Million barrels

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 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, crude oil and refined products terminals, chemicals pipelines, natural gas processing plants, and LNG infrastructure assets. Shell or its affiliates are customers of all of our businesses.  

SPLC is Shell’s principal midstream subsidiary in the United States. SPLC owns our general partner, a 57.4% limited partner interest in us and all of our incentive distribution rights.

Competition

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. Additionally, Zydeco is supported by FERC-approved transportation services agreements for the majority of the capacity available on the pipeline. 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.

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Our offshore crude oil pipelines are partially supported by life-of-lease 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 reserves will be subject to our ability, or the producers’ ability, to fund the significant 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. As a result of our contractual relationships, the markets they serve, and the size and scale of our refined products pipelines, we believe that our refined product pipelines will not face significant new competition in the near-term.

At Lockport, our storage tanks are currently leased at 100.0% capacity under long-term contracts, and some contracts also guarantee payments for minimum monthly throughput volumes. A competing pipeline from Flannigan to Patoka, Illinois, owned by Enbridge Inc. and Marathon Petroleum Company, was completed in the fourth quarter of 2015 primarily to transport Bakken crude oil, which was being previously shipped via railcars. This new pipeline will have no immediate material impact on our Lockport operations due to our long-term contracts. The use of pipelines to transport Bakken crude oil may eventually increase demand for storage and throughput at Lockport.

Control Center Operations

The pipeline, storage and terminal systems that are operated by SPLC’s employees are controlled from a central control room located in Houston, Texas. The control center operates with a Supervisory Control and Data Acquisition (SCADA) system equipped with computer systems designed to continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and alarm conditions. The control center operates remote pumps, motors, and valves associated with the receipt and delivery of crude oil and refined products, and provides for the remote-controlled shutdown of pump stations and valves on the pipeline system. A fully functional back-up operations center is also maintained and routinely operated throughout the year to ensure safe and reliable operations.

Colonial operates its pipeline system and Bengal’s tankage in a similar manner and has its own management team based in Alpharetta, Georgia.

FERC and State Common Carrier Regulations

Our interstate common carrier and state intrastate pipeline systems are subject to regulation by various federal, state and local agencies.

FERC regulates interstate transportation on our common carrier pipeline systems under the Interstate Commerce Act of 1887 as modified by the Elkins Act (“ICA”), the Energy Policy Act of 1992 (“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 conducted by FERC, such as the audit of Colonial. FERC’s Office of Enforcement concluded an audit of Colonial in Docket No. FA14-4-000 for

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the period January 1, 2011 to December 31, 2014, and issued a letter order on June 17, 2015 adopting the audit’s findings and recommendations and requiring Colonial to submit a compliance plan and quarterly compliance reports.   Colonial accepted the audit’s findings and recommendations, which had no financial impact to us.  

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.” 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:

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 FERC ruling is still subject to appeal. 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. Zydeco, Mars, Bengal and Colonial each made indexing filings in 2015 to increase applicable rates to a level at or below the index ceilings (certain of Zydeco’s rates were subsequently revised by a settlement, as discussed below). Rate increases made under the index 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 ratemaking, 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 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. 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.

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 Colonial and Zydeco pipeline rates; and the Louisiana Public Service Commission, which currently regulates the Mars, Colonial and Zydeco 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 order us to reduce our rates and require the payment of refunds to shippers.

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Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:

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 of our pipelines, including Auger 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 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 Safety

Our assets are subject to increasingly strict safety laws and regulations. Our transportation and storage of crude oil and refined products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, and significant business interruption. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the Department of Transportation (“DOT”) has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and necessary maintenance or repairs. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

We are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). 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 High Consequence Areas (“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 United States 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. We 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.

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 of new pipelines (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). On October 1, 2015, PHMSA proposed to extend reporting requirements to currently unregulated hazardous liquid gravity-flow and gathering lines, and to require additional or enhanced inspection, monitoring, data integration and repair programs for many currently regulated lines.

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The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act, 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 results of 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. In addition, PHMSA recently published an advisory bulletin providing guidance on verification of records related to pipeline maximum allowable operating pressure. We have performed hydrotests of our facilities to confirm the maximum allowable operating pressure and do not expect that any final rulemaking by PHMSA regarding verification of maximum allowable operating pressure would materially affect our operations or revenue. In addition, states have adopted regulations, similar to existing PHMSA regulations, for intrastate gathering and transmission lines. The states in which 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 crude oil.

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 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 U.S. Environmental Protection Agency (“EPA”) regulations.  Every tank periodically receives a full out of service, internal inspection per American Petroleum Institute standard 653 and is repaired as necessary to ensure long term integrity and reliability. 

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 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.

While we are not currently subject to governmental standards for the protection of computer-based systems and technology from cyber threats and attacks, proposals to establish such standards are being considered by the U.S. Congress and by U.S. Executive Branch departments and agencies, including the Department of Homeland Security, and we may become subject to such standards in the future. We are currently implementing our own cyber-security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material effect on operations and those of our customers.

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 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

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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. We cannot currently determine the amounts of such future impacts.

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 United States. These include requirements effective in 2010 to report emissions of greenhouse gases 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 September 2015, EPA proposed new rules for volatile organic compound and methane emissions from the oil and gas 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 United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement.  The Paris Agreement will be open for signing on April 22, 2016 and will require 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. The impact of future regulatory and legislative developments, if adopted or enacted, including any cap-and-trade program or any carbon-based taxing initiative, is likely to 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.

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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. Pursuant to the omnibus agreement we entered into on November 3, 2014 with SPLC (“Omnibus Agreement”), SPLC indemnifies us and will fund all of the costs of required remedial action for our known historical and legacy spills and releases and, subject to a deductible of $0.5 million per claim and aggregate monetary cap of $15.0 million for all environmental, title and litigation claims, for spills and releases, if any, existing but unknown at the time of closing of the IPO to the extent such existing but unknown spills and releases are identified within three years after closing of the IPO.

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 increase 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.

Indemnity Under the Omnibus Agreement. Under the Omnibus Agreement, SPLC will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets and due to occurrences on or before November 3, 2014, the closing date of the IPO. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of the IPO and identified prior to the third anniversary of the closing of the IPO, and will be subject to an aggregate deductible of $0.5 million before we are entitled to indemnification for losses incurred in excess of that deductible. Once we meet the deductible, SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15.0 million. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at our facilities, or for any other environmental liabilities resulting from our own operations. In addition, we have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets due to occurrences after the closing of the IPO and for environmental liabilities related to our assets to the extent SPLC is not required to indemnify us for such liabilities. Liabilities for which we will indemnify SPLC pursuant to the Omnibus Agreement are not subject to a deductible before SPLC is entitled to indemnification. There is no limit on the amount for which we will indemnify SPLC under the Omnibus Agreement. As a result, we may incur such expenses in the future, which may be substantial.

Indemnity Under the May 2015 Purchase Agreement. Under our purchase and sale agreement with SPLC we acquired (the “May 2015 Acquisition”) an additional 19.5% interest in Zydeco and an additional 1.388% interest in Colonial (the “Purchase and Sale Agreement”). SPLC will indemnify us for losses arising from SPLC’s breach of representations or warranties relating to environmental matters that are associated with the ownership or operation of the assets held by Zydeco and due to occurrences on or before May 18, 2015, the closing date of the May 2015 Acquisition. SPLC’s indemnification for breaches of representations or warranties relating to environmental matters will terminate and expire on the third anniversary of the closing date of the May 2015 Acquisition, and will be subject to an aggregate deductible of $1.0 million for any breaches of representations and warranties under the Purchase and Sale Agreement before we are entitled to indemnification for losses incurred in excess of that deductible.  Once we meet the deductible, SPLC’s indemnity obligation for all breaches of representations and warranties under the Purchase and Sale Agreement is capped at $44.8 million. Damages incurred under the Purchase and Sale Agreement are limited to 19.5% of the total of damages incurred as a result of a breach of representations or warranties relating to environmental matters that are associated with the ownership or operation of the assets held by Zydeco. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at our facilities, or for any other environmental liabilities resulting from our own operations.

Indemnity Under the Poseidon Contribution Agreement. Under our purchase and sale agreement with SOPUS for Poseidon (the “Poseidon Contribution Agreement”), SPLC will indemnify us for losses arising from SOPUS’s breach of representations or warranties relating to environmental matters that are associated with the ownership or operation of the assets held by Pecten and due to occurrences on or before July 1, 2015, the closing date of our acquisition of Poseidon. SPLC’s indemnification for breaches of

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representations or warranties relating to environmental matters will terminate and expire on the third anniversary of the closing date of acquisition of Poseidon, and will be subject to an aggregate deductible of $1.0 million for any breaches of representations and warranties under the Poseidon Contribution Agreement before we are entitled to indemnification for losses incurred in excess of that deductible.  Once we meet the deductible, SPLC’s indemnity obligation for all breaches of representations and warranties under the Poseidon Contribution Agreement is capped at $35.0 million. Damages incurred under the Poseidon Contribution Agreement are limited to 36.0% of the total of damages incurred as a result of a breach of representations or warranties relating to environmental matters that are associated with the ownership or operation of the assets held by Poseidon. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at our facilities, or for any other environmental liabilities resulting from our own operations.

Indemnity Under the Pecten Contribution Agreement. Under our contribution agreement with SPLC for Pecten (the “Pecten Contribution Agreement”), SPLC will indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of Auger and Lockport and due to occurrences on or before October 1, 2015, the closing date of our acquisition of Pecten. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing date of our acquisition of Pecten and identified, to the extent they relate to Auger, prior to the third anniversary, and, to the extent they relate to Lockport, prior to the fourth anniversary, of the closing date of our acquisition of Pecten.  SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $78.0 million. We will not be indemnified for any future spills or releases of hydrocarbons or hazardous materials at Auger and Lockport, or for any other environmental liabilities resulting from our operations. In addition, we have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of Auger and Lockport due to occurrences after October 1, 2015 and for environmental liabilities related to our assets to the extent SPLC is not required to indemnify us for such liabilities. Liabilities for which we will indemnify SPLC pursuant to the Pecten Contribution Agreement are not subject to a deductible before SPLC is entitled to indemnification. There is no limit on the amount for which we will indemnify SPLC under the Pecten Contribution Agreement. As a result, we may incur such expenses in the future, which may be substantial.

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 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 United States 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.

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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.

Insurance

All our assets other than Mars are insured at the entity level for certain property damage, business interruption and third-party liabilities, which include pollution liabilities, in amounts which management believes are reasonable and appropriate. Mars is self-insured by its current owners; however, we carry commercial insurance (other than named windstorm coverage) for our pro rata portion of Mars’ liabilities.

Employees

We do not have any employees. We are managed and operated by the directors and officers of our general partner. Zydeco, Mars, Bengal and Auger’s pipeline systems, and Lockport’s storage and terminal systems are operated by SPLC’s employees pursuant to operating and maintenance agreements with the entities that own such pipelines. Colonial is operated by its employees. Employees of Colonial operate Bengal’s tankage. Employees of an affiliate of the other member of Poseidon operate Poseidon’s pipelines. See Part III, Item 10. Directors, Executive Officers and Corporate Governance — Management of Shell Midstream Partners, L.P.  in this report.

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.

 

 

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:

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We do not control certain of the entities that own our assets.

We have no significant assets other than our ownership interest in Zydeco, Pecten, Mars, Bengal, Poseidon and Colonial. 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:

For a more complete description of 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 — Contracts with Affiliates and Part I, Items 1 and 2. Business and Properties — Our Assets and Operations in this report.

If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. Other than our revolving credit facilities, we do not have any commitment with any of our affiliates to provide any direct or indirect financial assistance to us.

If we do not make sufficient or effective expansion capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions. We will be required to use cash from our operations, incur borrowings or access the capital markets in order to fund our expansion capital expenditures. 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. The recent 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.

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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:

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.

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:

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, results of operations and cash flows, including our ability to make distributions.

If third-party pipelines, production platforms, refineries, caverns and other facilities interconnected to our pipelines 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. Because

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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 the Bureau of Safety and Environmental Enforcement (“BSEE”) or the Bureau of Ocean Energy Management (“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. Any temporary or permanent interruption at any key pipeline or terminal interconnect, at any key production platform or refinery or at caverns to which we deliver could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make distributions.

Lockport, our crude storage terminal, is located southwest of Chicago. Our terminal facilities depend on pipeline systems that are owned and operated by third parties. Any interruption of service on the pipeline or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our terminal facilities and have a corresponding material adverse effect on our revenues. Increases in the rates charged by the interconnected pipelines for transportation to and from our terminal facilities may reduce the utilization of Lockport.

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.

Beginning in the fourth quarter of 2014, crude oil prices significantly declined and continued to decline through early 2016 to the lowest levels in recent history. High, low and average daily prices for West Texas Intermediate (“WTI”) crude oil at Cushing, Oklahoma during 2014, 2015 and January 2016 were as follows:

 

 

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 (“OPEC”) and other oil producing nations; the price and availability of alternative fuels; 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.

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 United States. If lower prices are sustained, it could lead to a material decrease in such activity both onshore continental United States 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 agreements that do not include a guaranteed return to the extent that production in the area we serve declines or is shut in.

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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 distributions.

Any significant decrease in the demand for crude oil and refined products could reduce the volumes of crude oil and refined products that we transport, which could adversely affect our revenue and available cash.

The volumes of crude oil and refined products that we transport depend on the supply and demand for crude oil, gasoline, jet fuel and other refined products in our geographic areas. Demand for crude oil and refined products 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.

If the demand for crude oil or refined products 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.

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.

Our assets other than Mars and Poseidon are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. Each of Mars’ and Poseidon’s current owners are required to carry insurance for their pro rata share. We carry commercial insurance for our pro rata portion of Mars’ and Poseidon’s potential liabilities, which will increase our general and administrative expenses. We do not carry named windstorm insurance for Mars or Poseidon, each of which is located in the Gulf of Mexico.

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 ranges from 21 days to 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 Hurricanes Katrina, Rita, Gustav and Ike have made it more difficult and more expensive to obtain certain types of coverage, and we may elect to self-insure portions of our asset portfolio. Moreover, the offshore entities in which we own an interest do not maintain insurance coverage for named windstorms. The occurrence of an event that is not fully covered by insurance, or failure by one or more insurers to honor its coverage commitments for an insured event, could have a material adverse effect on our business, financial condition 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. We cannot assure you 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 distributions.

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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 distributions

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

In order to optimize our existing asset base, we intend to evaluate and capitalize on organic opportunities for expansion projects in order to increase revenue on our assets. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost.

We also intend to expand our existing pipelines and terminal, such as by adding horsepower, pump stations, new connections or additional tank storage. We expect to complete several expansion and upgrade projects, including the Houma electrical transformer addition, pump stations, new connections, land purchases and possible pipeline expansion.  

These expansion projects involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If any expansion projects we undertake are not completed on schedule, certain agreements that we have entered into in anticipation of such expansion projects being completed may not be effective for their full volume.

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. For example, we expect to transport increased volumes on Mars as a result of our Mars expansion project and, among other things, additional volumes from the Amberjack pipeline at the interconnection of Mars with the Amberjack pipeline. However, anticipated volume increases may not materialize, and we may not realize an increase in revenue as a result of the Mars expansion project or realize the full benefit from this interconnection. 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 distributions.

We do not own all of the land on which our pipelines are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines are located, and we are, therefore, subject to the possibility of more onerous terms and increased costs to retain necessary land use if we do not have valid leases or rights-of-way or if such rights-of-way lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies, and some of our agreements may grant us those rights for only a specific period of time. Our loss of these rights, through our inability to renew leases, right-of-way contracts or otherwise, or inability to obtain 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 and refined products 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.

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On January 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”) was signed into law. The 2011 Pipeline Safety Act, among other things:

PHMSA has begun to undertake the various requirements imposed on it by the legislation, which will impose additional costs on new pipeline projects as well as on existing operations. In March 2015, PHSMA issued final regulations that include a prohibition on individuals involved in the construction of a transmission line, main or pipeline system from inspecting his or her own work; the addition of annual leak surveys for Type B gathering lines; and the addition of ethanol to the definition of hazardous liquids transported by pipeline. In addition, PHMSA is considering new regulations to require more frequent inspections of tanks, new operator qualification requirements for pipeline construction and changes to operator qualification rules, including enhanced enforcement. Compliance with these requirements will increase costs if adopted. In addition, on October 1, 2015, PHMSA proposed to extend regulation to currently unregulated crude oil and hazardous liquid pipelines, and to require additional inspection, monitoring, and repair programs for many currently regulated lines.

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, greenhouse gas (“GHG”) emissions, waste management, species and habitat preservation, pollution prevention, pipeline integrity and other safety-related regulations and characteristics and composition of fuels. Certain of these laws and regulations could impose obligations to conduct assessment or remediation efforts at our facilities or third-party sites where we take wastes for disposal or where our wastes migrated, 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 (“NAAQS”) for ozone, sulfur dioxide and nitrogen dioxide, and the EPA is considering further revisions to the ozone and sulfur dioxide NAAQS. 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.

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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 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 on our common units.

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 on our common units.

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

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:

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 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.

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.

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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 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 on our common units.

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 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 on its system.  Several shippers protested the filing, and FERC issued an order on December 3, 2015 suspending the effectiveness of the tariffs until July 4, 2016, subject to further order following a technical conference on the issues raised by the protestors.  Because this proceeding is ongoing, the outcome is not known at this time.

We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC, such as the audit of Colonial. FERC’s Office of Enforcement concluded an audit of Colonial in Docket No. FA14-4-000 and issued a letter order on June 17, 2015 adopting the audit’s findings and recommendations.  Colonial accepted the audit’s findings and recommendations, which had no financial impact to us.

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

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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 Numbers 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, 2015.

Further, rate investigations by FERC or a state commission could result in an investigation of our costs, including the:

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 United States. We do not maintain specialized insurance for possible liability or loss resulting from a cyber-attack on our assets that may shut down all or part of our business. Instability in the financial markets as a result of terrorism or war could also affect our ability to raise capital including our ability to repay or refinance debt. It is possible that any of these occurrences, or a combination of them, could have a material 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 revolving 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 entered into two revolving credit facilities and Zydeco has entered into a senior unsecured revolving credit facility with an affiliate of Shell with a total capacity of $610.0 million, under which a total of $458.2 million was drawn as of December 31, 2015. Borrowings under our revolving credit facilities were used to fund in part our acquisition of additional interests in Zydeco and Colonial, an interest in Poseidon and 100.0% of the equity of Pecten.  Borrowings under Zydeco’s credit facility were used for capital projects and operating expenses.  Restrictions in our revolving 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.

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The restrictions in our revolving 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 revolving 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 — Revolving Credit Facility Agreements in this report for additional information about our revolving 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 future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price is impacted by our level of 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 product loss allowance exposes us to commodity risk.

Our long-term transportation agreements and tariffs for crude oil shipments include a product loss allowance. We collect product 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 commodity prices.

The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our common unitholders.

We rely on revenue generated from our pipelines, which are primarily located along the Texas and Louisiana Gulf Coast and offshore Louisiana, and from Lockport, which is located southwest of Chicago. 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.

Our assets include partial ownership interests in Zydeco, Mars, Bengal, Poseidon, Colonial and a wholly owned interest in Pecten. 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.

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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, 2015, SPLC owned a 57.4% 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:

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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 (including the net proceeds that we retained from the IPO) and external financing sources, including borrowings under our revolving 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 revolving 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 $600.0 million. 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 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, we pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. 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. 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:

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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 and subordinated 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.

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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 and subordinated units voting together as a single class is required to remove our general partner. As of December 31, 2015, our general partner and its affiliates owned 25.5% of our common units and all of our subordinated units, representing an aggregate 57.4% of our outstanding common and subordinated units. If our general partner is removed without cause during the subordination period and units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated units will automatically convert into common units and any existing arrearages on our common units will be extinguished, thereby eliminating the distribution and liquidation preference of common units. “Cause” is narrowly defined to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding our general partner liable to us or any limited partner for actual fraud or willful misconduct in its capacity as our general partner. “Cause” does not include most cases of charges of poor management of the business, so the removal of our general partner because of unitholder dissatisfaction with the performance of our general partner in managing our partnership will most likely result in the termination of the subordination period and conversion of all subordinated units to common units.

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.

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 Partnership 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:

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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, 2015, SPLC held 21,475,068 common units and 67,475,068 subordinated units. All of the subordinated units will convert into common units at the end of the subordination period and may convert earlier under certain circumstances. 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 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, 2015, our general partner and its affiliates owned approximately 25.5% 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 there are no subordinated units outstanding and the holders have received incentive distributions at the highest level to which they are entitled (48.0%, in addition to distributions paid on its 2.0% 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.

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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:

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.

A “material weakness” is a deficiency, or combination of deficiencies, in internal controls such that there is a reasonable possibility that a material misstatement in financial statements will not be prevented or detected on a timely basis.

We revised our Predecessor’s unaudited condensed combined statements of operations, the unaudited condensed combined statements of changes in net parent investment, and the unaudited condensed combined statements of cash flows for the three months ended March 31, 2013. The revision was due to errors in the recording of the accrual of revenues and recording of loss/gain from pipeline operations during the three months ended March 31, 2013. Accordingly, we identified a material weakness in our internal controls over the preparation of these interim financial statements, specifically, determining the completeness and accuracy of the journal entries required to properly accrue revenues and record loss/gain from pipeline operations.

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Subsequently we restated our Predecessor’s combined audited financial statements as of and for 2013 and revised our combined financial statements as of and for the six-month period ended June 30, 2014. The restatement and revision were due to a data entry error resulting in the under-recognition of revenue to the Predecessor pipeline during 2013. Effective controls were not designed or operated to review the accuracy of tariff rates and associated inputs which impact the accuracy and reporting of revenues. Accordingly, our management has determined that this control deficiency constituted a material weakness.

As a result of the material weaknesses described above, we standardized processes, segregated financial data within our accounting systems, and implemented further controls to validate our financial data.  Further, we engaged a third party internal controls specialist firm to assist our management in a review of our existing control framework, the determination, development and implementation of new controls, the documentation of processes and the performance of control testing.  Additional controls were implemented to mitigate the associated risks and to support the completeness and accuracy of our financial reporting.  We have concluded that the material weaknesses previously identified had been remediated as of December 31, 2015. However, we may identify additional material weaknesses in our internal control over financial reporting in the future.

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. Our Partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. A unitholder could be liable for any and all of our obligations as if a unitholder were a general partner if a court or government agency were to determine that (i) we were conducting business in a state but had not complied with that particular state’s partnership statute; or (ii) a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

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 the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

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.

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Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. 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. For example, the Obama administration's budget proposal for fiscal year 2017 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration's proposal or other similar proposals 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. Additionally, on May 6, 2015, the IRS and the U.S. Department of the Treasury published proposed regulations that provide industry-specific guidance regarding whether income earned from certain activities will constitute qualifying income. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, or whether proposed regulations, once issued in final form, 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’ share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

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

If the IRS contests the 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.

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.

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

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal income tax returns and applicable state tax returns and pay tax on their share of our taxable income.

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 recently 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.

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.  

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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.

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.

The sale or exchange of 50.0% or more of our capital and profits interests during any twelve month period will result in the termination of our partnership for federal income tax purposes. The sale or exchange of 50.0% or more of the capital and profits interests in any entity in which we own an interest that is treated as a partnership for federal income tax purposes during any twelve month period will result in the termination of such partnership for federal income tax purposes.

We will be considered to have technically terminated our existing partnership and having formed a new partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve month period. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if certain relief were unavailable) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in the unitholder’s taxable income for the year of termination. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

We own material interests in entities treated as partnerships for federal income tax purposes. Any of these entities will be considered to have technically terminated and to have formed a new partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in such entity’s capital and profits within a twelve month period. Such a termination could result in a deferral of depreciation deductions allowable in computing our taxable income.

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 you.

If our assets are subjected to a material amount of additional entity-level taxation by individual states, our cash available for a distribution to you would be reduced. Currently, several states are 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 Illinois, Louisiana and Texas. Illinois imposes an entity-level tax on partnerships at a rate of 1.5% of partnership income apportioned to Illinois, and Texas imposes a franchise tax on all business entities (including partnerships) at a maximum effective rate of 0.5% of the business’ gross income apportioned to Texas. In the future, we may expand our operations. Imposition of a similar tax on us in other jurisdictions that we may expand to could substantially reduce our cash available for distribution to you.

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

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. We conduct business and/or control assets in Illinois, Louisiana and Texas. Illinois and Louisiana currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is each unitholder’s responsibility to file all federal, state and local tax returns. 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.

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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 Colonial, a C corporation. Such C corporations are subject to federal income tax on their taxable income at the corporate tax rate, which is currently a maximum of 35.0%, 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, 2015, the maximum federal income tax rate applicable to such qualified dividend income which is allocable to individuals was generally 20.0%. An individual unitholder’s share of dividend and interest income from Colonial or other C corporation subsidiaries would constitute portfolio income that could not be offset by the unitholder’s 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 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 SPLC or SOPUS since the IPO, SPLC or SOPUS, 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 uncommitted (or non-contract) rates for uncommitted 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). For more information on the rate case, see Item 1A. Risk Factors — Risks Related to Our Business in this report. We accrued $2.3 million for the settlement as of December 31, 2015 which was paid in January 2016. The Partnership has the right under the Omnibus Agreement to seek indemnity from SPLC for some of the costs incurred. 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.

Item 4. MINE SAFETY DISCLOSURES

Not applicable.

 

 

 

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PART II

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

Quarterly Common Unit Prices and Cash Distributions Per Unit

On October 29, 2014, our common units began trading on the New York Stock Exchange (NYSE) under the symbol “SHLX.” The following table reflects intraday high and low sales prices per common unit and cash distributions declared to unitholders for each quarter starting on November 3, 2014:

 

⁽¹⁾  The fourth quarter 2014 minimum quarterly distribution was prorated for the 59-day period from November 3, 2014 to December 31, 2014 in accordance with the Partnership Agreement.

As of February 26, 2016, SPLC owned all of our incentive distribution rights, 21,475,068 common units, 67,475,068 subordinated units, and 3,098,825 general partner units, (representing the 2.0% general partner interest), which together constitutes a 59.4%  ownership interest in us. As of February 1, 2016, we had three 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:

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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 a minimum quarterly distribution to the holders of our common units and subordinated units of $0.1625 per unit, or $0.6500 per unit on an annualized basis, to the extent we have sufficient available cash after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity — Revolving Credit Facility Agreements in this report, for a discussion of the restrictions included in our revolving credit facilities that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

Initially, our general partner is entitled to 2.0% of all quarterly distributions since our inception that we make prior to our liquidation. This general partner interest is represented by 3,098,825 general partner units. Our general partner has the right, but not the obligation, to contribute up to a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2.0% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2.0% 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, subordinated or general partner units that they own.

Percentage Allocations of Available Cash from Operating Surplus

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under Marginal Percentage Interest in Distributions are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column 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 2.0% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2.0% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 

Subordination Period

General

Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.1625 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of

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the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed “subordinated” because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will accrue or be payable on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

Subordination Period

Except as described below, the subordination period began on the closing date of our IPO and extends until the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending December 31, 2017, that each of the following tests are met:

Early Termination of Subordination Period

Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter beginning with the quarter ending December 31, 2015, that each of the following tests are met:

Expiration Upon Removal of the General Partner

In addition, if the unitholders remove our general partner other than for cause:

Expiration of the Subordination Period

When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

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Item 6. SELECTED FINANCIAL DATA

The acquisition of Pecten, which owns the Shell Auger and Lockport Operations, was a transfer of businesses between entities under common control, which requires prior periods to be retrospectively adjusted as if the Partnership owned the Shell Auger and Lockport Operations for the periods prior to the acquisition. Accordingly, the accompanying financial information for periods prior to October 1, 2015 (the effective date of the acquisition) have been retrospectively adjusted to include the historical results and financial position of the Shell Auger and Lockport Operations prior to the effective date of the acquisition as if such businesses had been combined for all periods presented. See Note 3 – Acquisitions in the Notes to Consolidated Financial Statements included in Part II, Item 8 of this report for additional information.

No adjustments have been made to historical periods to reflect other acquisitions completed in 2015, as each of these acquisitions were asset acquisitions required to be reflected in the historical financial statements on a prospective basis from the effective date of the acquisition.

All financial information presented for periods prior to the IPO represents the consolidated results of operations, financial position and cash flows of our Predecessor giving retrospective effect to the combined results of operations, financial position and cash flows of the Shell Auger and Lockport Operations.  All financial information presented for periods after the IPO represents the consolidated results of operations, financial position and cash flows of the Partnership giving retrospective effect to the combined results of operations, financial position and cash flows of the Shell Auger and Lockport Operations prior to the effective date of its acquisition on October 1, 2015.

Accordingly:

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.

 

 

⁽¹⁾ All prior-period financial information has been retrospectively adjusted for the Shell Auger and Lockport Operation prior to the effective date of its acquisition on October 1, 2015.

⁽²⁾ Information is not applicable for periods prior to the IPO.

⁽³⁾ 2014 distributions per limited partner unit represents the pro-rated minimum quarterly distribution for the period from November 3, 2014 and December 31, 2014.

 

 

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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 Partnership’s analysis of its 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.

Partnership Overview

We are a fee-based, growth-oriented master limited partnership formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our assets consist of interests in entities that own crude oil and refined products pipelines and terminals serving as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast and Midwest refining markets and to deliver refined products from Gulf Coast markets to major demand centers. We generate the majority of our revenue under long-term agreements by charging fees for the transportation or storage of crude oil and refined products through our pipelines. We do not engage in the marketing and trading of any commodities.

For a description of our assets, please see Part I, Item 1 — Business and Properties of this report.

How We Generate Revenue

All but our Lockport assets generate revenue under four types of long-term transportation agreements: transportation services agreements, throughput and deficiency agreements, life-of-lease agreements and life-of-lease agreements with a guaranteed return. Our transportation services agreements have initial terms ranging from five to fifteen years; our throughput and deficiency agreements have initial terms of ten years or more; and our life-of-lease agreements have a term equal to the life of the applicable mineral lease. We also transport volumes on a short-term basis through posted tariffs, also known as a spot rate basis. In addition, direct connected producers transport volumes based on posted rate sheets. Many of our transportation agreements include a provision to allow us to adjust the rate annually based on the FERC index, which adjusts on July 1 of each year. There is no requirement to reduce the rate when the FERC index is negative, other than spot rates if our rates were to exceed the adjusted index ceiling.

All of Lockport’s tank capacity is leased under long-term guaranteed storage tank services and throughput agreements.

Zydeco’s FERC-approved transportation services agreements entitle the customer to a specified amount of guaranteed capacity on a 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 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.

Our throughput and deficiency agreements establish a minimum, annual average volume for each year during a fixed period. If the customer falls below the minimum volume in a year, it is required to pay a deficiency payment equal to the difference at the end of the year. Typically, surplus volumes in a year can be reserved for use in subsequent years where there is a deficiency. We refer to our transportation services agreements and our throughput and deficiency agreements as “ship-or-pay” contracts.

Our life-of-lease agreements, some of which have a guaranteed return for us, require producers to transport all production from the specified fields connected to the pipeline for the life of the lease. This means that the dedicated production cannot be transported by any other means, such as barges or another pipeline. These agreements can also include provisions to guarantee a return to the pipeline to enable the pipeline to recover its investment 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 based on actual project costs and operating costs. At the end of the fixed period, the rate will be locked in at the last calculated rate and adjusted thereafter based on the FERC index.

Our long-term transportation agreements and tariffs for crude oil transportation include product loss allowance (“PLA”). PLA is 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. PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The 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.

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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 PLA) from contracted capacity and throughput; (ii) operations and maintenance expenses; (iii) Adjusted EBITDA (defined below); and (iv) cash available for distribution.

Contracted Capacity and Throughput

The amount of revenue our business generates primarily depends on our long-term transportation agreements with shippers and the volumes of crude oil and refined products that we handle on our pipelines and storage tanks. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we have the right to charge for reserved capacity or for deficiency payments as described in “—How We Generate Revenue”. We also earn revenue by shipping crude oil and refined products on a spot rate basis in accordance with our tariff.

The commitments under our long-term transportation agreements with shippers and the volumes which we handle on our pipelines and storage tanks are primarily affected by the supply of, and demand for, crude oil and refined products in the markets served directly or indirectly by our assets. This supply and demand is impacted by the market prices for crude oil and refined products. Our results of operations will be impacted by our ability to:

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), 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. Our other operations and maintenance expenses generally remain relatively 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 that period. We will seek to manage our maintenance expenditures on the pipelines and storage tanks we operate by scheduling maintenance over time to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flow, without compromising our commitment to safety and environmental stewardship.

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, accretion and amortization, plus cash distributed to the Partnership 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. 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.

We compute and present cash available for distribution and define it 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.

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:

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We believe that the presentation of Adjusted EBITDA and cash available for distribution provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and cash available for distribution are net income attributable to the Partnership 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. Adjusted EBITDA and cash available for distribution have important limitations as an analytical tool because it excludes 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 its utility. Please refer to the Reconciliation of non-GAAP Measures section of Results of Operations for the reconciliation of net income and cash provided by operating activities to Adjusted EBITDA and cash available for distribution.

Factors Affecting the Comparability of Our Financial Results

Our historical results of operations for the periods after the IPO will not be comparable to our Predecessor’s historical results of operations for periods prior to the IPO for the reasons described below:

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Factors Affecting Our Business and Outlook

Substantially all of our revenue is derived from long-term transportation and storage agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return, and long-term storage agreements with crude oil suppliers to refineries. We believe the commercial terms of these long-term transportation and storage agreements substantially mitigate volatility in our cash flows by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business can, however, be negatively affected by sustained downturns or sluggishness in 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.

We believe key factors that impact our business are the supply of, and demand for, crude oil and refined products in the markets in which our business operates. We also believe that our customers’ requirements and government regulation of crude oil and refined products pipelines, discussed in more detail below, play an important role in how we manage our operations and implement our long-term strategies.

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 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. While these changes in the sourcing patterns of crude oil transported 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.

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.

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.

Changes in Commodity Prices

We do not engage in the marketing and trading of any commodities. On our Poseidon system, we transport crude oil using buy-sell contracts where we buy the oil at the wellhead and sell it back to the shipper at another point on our pipeline at a pre-determined price marked up for transportation. Except for PLA, we do not take ownership of the crude oil or refined products for any other of our pipelines or terminals. As a result, our direct exposure to commodity price fluctuations is limited to the PLA provisions in our tariffs. We also have indirect exposure to commodity price fluctuations to the extent such fluctuations affect the shipping patterns of our customers.

Crude oil prices declined substantially during 2015 and early 2016 and prices are not forecasted to increase materially in the near future.  The capital markets have also become less accessible since mid-2015. The current global geopolitical and economic uncertainty may contribute to continued volatility in financial and commodity markets in the near to medium term. We have not experienced a decline in throughput volumes on Zydeco, Mars, Poseidon and Auger, our crude oil pipeline systems, as a result of lower crude oil prices. In addition to benefitting from the long-term fee based arrangements described above, these pipeline systems 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 even in the current weak price environment. We expect that transportation volumes on Zydeco, Mars, Poseidon and Auger will continue to increase in the near term as significant deepwater production areas ramp up production, we execute continued debottlenecking efforts, and Zydeco brings a new connection on line. However, if crude oil prices remain at low 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 terminate our contracts or renegotiate our contracts on terms that are less attractive to us or impair their ability to perform under our contracts.

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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. In the current market of high refinery margins, we are experiencing high demand for our pipeline systems servicing refineries. 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.

Major Maintenance Projects

We have three major maintenance projects planned for 2016.

On the Zydeco pipeline system, we are currently in the permitting 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.  Due to delays in permitting, the project has been postponed to the fourth quarter of 2016 to allow performance of the work during optimal weather and water conditions. Zydeco expects to incur approximately $20.0 million in maintenance capital expenditures for the total project, of which approximately $12.5 million would be attributable to the Partnership’s ownership share. We intend to finance the Partnership’s pro rata share of these expenditures from cash on hand; or borrowings under our working capital facility.  In connection with the acquisition of additional interest in Zydeco in May 2015, SPLC agreed to reimburse the Partnership against the Partnership’s proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2015 with respect to the project. As of December 31, 2015, Zydeco has incurred $2.0 million of capitalized costs related to this project.

We expect Auger and Lockport’s maintenance capital expenditures to be approximately $10.0 million for 2016.  This includes $4.8 million for electrical and storm water upgrades at Lockport, and $5.2 million for control system upgrade and personnel escape pods at Ship Shoal 28 for Auger.

Major Expansion Projects

We expect Zydeco’s expansion capital expenditures to be $30.1 million for Houma upgrades and expansion, including electrical transformer, pump stations, new connections, land purchases and a possible pipeline expansion.  

Customers

We transport and store crude oil and refined products for a broad mix of customers, including crude oil producers, refiners, marketers and traders, and are connected to other crude oil and refined products pipelines. In addition to serving directly-connected Gulf Coast markets, our 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. Producers of crude oil 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.

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. 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. As a result of a substantial majority of our capacity being reserved on a long-term, fixed-rate basis, our revenue is not significantly affected by variation in customers’ actual usage.

 

Our Lockport storage terminal competes with surrounding providers of storage tank services. Some of our competitors may expand or third parties may construct pipelines that bypass our location. These, or similar events, will have no immediate material impact on our Lockport operations due to our long-term contracts with contracted storage fees and payments for minimum monthly throughput volumes.

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Regulation

Our assets are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, see Part I, Items 1 and 3. Business and Properties in this report.

Acquisition Opportunities

We plan to pursue acquisitions of complementary assets from SPLC and other subsidiaries of Shell, as well as from third parties. 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 over the next few years. We executed three acquisitions from SPLC or its affiliates in 2015, including the acquisition of additional interests in Zydeco and Colonial in May 2015, the acquisition of a 36.0% interest in Poseidon in July 2015, and the acquisition of a 100.0% interest in Pecten in November 2015. 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 initially focus our acquisition strategy on transportation and midstream assets within the crude oil and refined products sectors. 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.

Seasonality

We do not expect that our operations will be subject to significant seasonal variation in demand or supply.

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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.

 

 

⁽¹⁾ Prior-period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations effective October 1, 2015.

⁽²⁾ Adjusted EBITDA attributable to Predecessors for 2015 is entirely attributable to Shell Auger and Lockport Operations through September 30, 2015.

⁽³⁾ Adjusted EBITDA attributable to Predecessors for 2014 includes $47.7 million attributable to Shell Auger and Lockport Operations prior to the acquisition and $95.2 attributable to Zydeco and Ho-Ho prior to the IPO.

⁽⁴⁾ Excluding non-recurring items (reimbursements from Parent and waiver payment), cash available for distribution attributable to the Partnership would be $169.8 million for 2015.

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⁽¹⁾ Prior-period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations effective October 1, 2015.

⁽²⁾ Net cash provided by operating activities includes $(0.6) million of income in excess of distributions.

⁽³⁾ Adjusted EBITDA attributable to Predecessors for 2015 is entirely attributable to Shell Auger and Lockport Operations through September 30, 2015.

⁽⁴⁾ Adjusted EBITDA attributable to Predecessors for 2014 includes $47.7 million attributable to Shell Auger and Lockport Operations prior to the acquisition and $95.2 attributable to Zydeco and Ho-Ho prior to the IPO.

⁽⁵⁾ Excluding non-recurring items (reimbursements from Parent and waiver payment), cash available for distribution attributable to the Partnership would be $169.8 million for 2015.

 

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Results of Operations

 

 

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations effective October 1, 2015.

⁽²⁾  Pipeline throughput is defined as the volume of delivered barrels.

⁽³⁾ Terminal throughput and storage is defined as the volume of stored barrels.

⁽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 and tenure of contract.

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2015 compared to 2014

Revenues

Total revenue increased by $76.2 million primarily due to $67.8 million in higher third-party transportation services by Zydeco. Total transportation services revenue increased by $77.9 million, or 33.5%, primarily due to a 10.9% increase in delivered volumes and higher revenue from incremental committed transportation agreements related to Zydeco.  Additionally, Zydeco’s tariffs escalated at the start of the third quarter 2015 in line with FERC escalation rates generating higher revenue in the second half of 2015, and we also recognized revenue associated with expiring credits on Zydeco’s committed transportation agreements.

Costs and Expenses

Total costs and expenses were $20.2 million higher in 2015 primarily due to $1.5 million of higher operations and maintenance expenses, $14.4 million of additional general and administrative expenses, $1.3 million in higher property taxes from higher property appraisals of the Zydeco assets, and $3.2 million depreciation expense due to capital additions related to the Zydeco pipeline expansion projects.

Operations and maintenance expenses increased by $1.5 million primarily due to:

General and administrative expenses increased by $14.4 million primarily due to:

Investment, dividend and other income in 2015 was $79.3 million due to the earnings from Mars, Bengal and Poseidon equity investments and the dividend from Colonial. Our investment, dividend and other income in 2014 was $7.5 million, as we did not have an investment in Mars, Bengal or Colonial until our IPO in 2014. Our investment ownership in Colonial increased on April 1, 2015 from 1.612% to 3.0%, and our investment in Poseidon commenced on July 1, 2015.

2014 compared to 2013

Revenues

Total revenue increased by $102.5 million due to $106.0 million in higher transportation services revenue offset by $3.5 million lower storage revenue. The $106.0 million increase in transportation services revenue consists of $91.4 million from the application of new contract rates and higher non-contract tariff rates associated with the Zydeco pipeline reversal completed at the end of 2013, $7.7 million from a combination of higher delivered volumes and tariffs for the Auger pipeline and $7.0 million revenue related to the reestablished connection between the Auger and Eugene Island pipelines. Storage services revenue decreased by $3.5 million primarily due to reduced need for storage in 2014 as a result of (i) the completion of the Zydeco pipeline reversal and (ii) volume incentives that reduced rental payments. Third party transportation services revenue increased by $91.4 million primarily due to the application of new contract rates in 2014. Related party transportation services revenue increased by $14.6 million primarily due to the higher volumes and tariffs together with the reestablished connection noted above.

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Costs and Expenses

Total costs and expenses were $31.3 million higher in 2014. Excluding the loss (gain) from disposition of fixed assets incurred in both years, total costs and expenses increased $10.3 million.

Operations and maintenance expenses decreased by $0.7 million primarily due to:

partially offset by,

General and administrative expenses increased by $5.2 million primarily due to approximately $2.0 million from the adoption of the management fees from Zydeco and the Partnership and approximately $2.0 million of higher third-party vendor costs related to the FERC rate protest involving the new Zydeco pipeline tariffs filed in December 2013.

Depreciation expense increased by $4.7 million and Texas and Louisiana property and other taxes increased by $1.1 million due to higher property appraisals in Louisiana and Texas associated with the Zydeco pipeline reversal and expansion. The West Columbia pipeline was sold in August 2013, resulting in a recognized gain on disposition of the pipeline of $20.8 million.  

Income from other investments was $7.5 million in 2014 due to the earnings from Mars and Bengal equity investments and the dividend from Colonial.

Capital Resources and Liquidity

After July 1, 2014, we established our own cash accounts. We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our revolving credit facilities. On February 22, 2016, the Partnership and STCW again amended the current credit facilities to extend the maturity dates to where the debt is long-term, thus eliminating short-term refinancing risk.  In addition, 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, 2015 was $244.8 million consisting of $93.0 million cash on hand and $151.8 million available capacity under our revolving credit facilities.

Revolving Credit Facility Agreements

Zydeco Revolver

Zydeco entered into a revolving credit facility (the “Zydeco Revolver”) with STCW, as the lender. The Zydeco Revolver has a borrowing capacity of $30.0 million. Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin. The credit agreement governing the Zydeco Revolver provides for covenants such as requiring pari passu ranking with any new indebtedness and contains customary events of default, such as nonpayment of principal when due, nonpayment of interest, fees or other amounts, violation of covenants, and cross-payment default (due to indebtedness in excess of $100.0 million). The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees and matures on August 6, 2019.  There were no outstanding borrowings on the Zydeco Revolver as of December 31, 2015 and 2014.

Five-Year Revolver

To provide additional liquidity following the IPO, we entered into a revolving credit facility agreement (the “Five-Year Revolver”) with STCW with an initial borrowing capacity of $300.0 million. Loans advanced under the initial agreement had up to a six-month term.

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On May 12, 2015, the Partnership and STCW amended and restated the Five-Year Revolver to increase the borrowing capacity amount from $300.0 million to $400.0 million.  In connection with this amendment and restatement of the Five-Year Revolver, the Partnership paid an issuance fee of $0.2 million. On February 22, 2016, the Partnership and STCW again amended and restated the Five-Year Revolver to provide that loans advanced under the facility would have maturity dates selected by the Partnership up to October 31, 2019, the maturity date of the Five-Year Revolver. This amendment and restatement allows the Partnership to roll over the outstanding balance until the maturity date of the Five-Year Revolver.

The Five-Year Revolver, as amended and restated, provides for covenants such as restricting additional indebtedness above $600.0 million and requiring pari passu ranking with any new indebtedness, and contains customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants, and cross-payment default (due to indebtedness in excess of $100.0 million). Borrowings under the Five-Year Revolver bear interest at the three-month LIBOR rate plus a margin. The Five-Year Revolver also provides for customary fees, including issuance and commitment fees. Commitment fees began to accrue on the date the Partnership entered into the Five-Year Revolver. The Five-Year Revolver matures on October 31, 2019. There were $320.8 million outstanding borrowings as of December 31, 2015 and no outstanding borrowings as of December 31, 2014.  

364-Day Revolver

On June 29, 2015, in connection with the July 2015 Acquisition, the Partnership entered into a second revolving credit facility (the “364-Day Revolver”) with STCW with an initial borrowing capacity of $100.0 million. Loans advanced under the initial agreement will mature on June 29, 2016.  All other terms and conditions are materially the same as those of the Five-Year Revolver.

On November 11, 2015, the Partnership and STCW amended and restated the 364-Day Revolver to increase the borrowing capacity amount from $100.0 million to $180.0 million.  In connection with this amendment and restatement of the 364-Day Revolver, the Partnership paid an issuance fee of $0.1 million.  On February 22, 2016, the Partnership and STCW again amended and restated the 364-Day Revolver to extend its maturity date to March 1, 2017. All other terms and conditions of the agreement were unchanged.

There were $137.4 million of outstanding borrowings under this facility as of December 31, 2015 and no outstanding borrowings as of December 31, 2014.  On February 22, 2016, the Partnership and STCW agreed to extend the maturity date on all outstanding borrowings under the 364 Day Revolver to March 1, 2017.

Total Debt Payable—Related Party

Borrowings under our debt facilities bear interest at the three-month LIBOR rate plus a margin. Our weighted average interest rate for 2015 was 1.7%. 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 debt of $458.2 million as of December 31, 2015 would increase our consolidated annual interest expense by approximately $0.6 million.

Our Five-Year Revolver and our 364-Day Revolver mature in October 31, 2019 and March 1, 2017, 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.

As of December 31, 2015, we were in compliance with the covenants contained in the Five-Year Revolver and the 364-Day Revolver, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

Cash Flows from Our Operations

Operating Activities. We generated $282.7 million in cash flow from operating activities in 2015 compared to $167.0 million in 2014. The $115.7 million increase in cash flows primarily resulted from higher third-party transportation services revenue, income from equity investments and nonrecurring decreases in liabilities related to the repair costs incurred in 2014 for the Zydeco reversal. These increases were partially offset by higher general and administrative expenses and recognition of deferred revenues due to expiration of committed shipper credits.

We generated $167.0 million in cash flow from operating activities in 2014, compared with $73.4 million in 2013. The $93.6 million increase in cash flows primarily resulted from an increase in revenue due to the application of new contract rates and higher non-contract tariff rates associated with the Zydeco reversal.

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Investing Activities. Our cash flow used in investing activities was $201.1 million in 2015 compared to $61.5 million in 2014. The increase in cash flow used in investing activities was primarily due to our acquisitions in 2015 and the payment of pre-IPO distributions from investments, partially offset by a decrease in expansion capital expenditures on the Zydeco pipeline system. See Note 3 – Acquisitions in the Notes to Consolidated Financial Statements in Part II, Item 8 of this report for additional information.

Our cash flow used in investing activities was $61.5 million in 2014, compared with $84.8 million in 2013 due to lower capital expenditures related to the Zydeco pipeline.

Financing Activities.  Our cash flow used in financing activities was $138.8 million in 2015 compared to $44.7 million provided by financing activities in 2014. The increase in cash flow used in financing activities was primarily due to the capital distributions to the general partner, quarterly distributions paid to the unitholders and the general partner, and distributions paid to the noncontrolling interest, partially offset by net proceeds from a private placement and public offering of common units, borrowings on the revolvers, reimbursements from Parent and cash contributions from our general partner.

Our cash flow provided by financing activities was $44.7 million in 2014 compared to $11.4 million in 2013. The increase in cash flow provided by financing activities was primarily due to $1,011.7 million net proceeds we received from the IPO in 2014, partially offset by IPO distributions of $911.7 million to SPLC, $25.2 million distributed to SPLC for its noncontrolling interest in Zydeco and $27.8 million of net distributions to Parent by the Predecessor.  

Capital Expenditures

Our operations can be capital intensive, requiring investments to expand, upgrade or enhance existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and expansion capital expenditures. 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 incurred capital expenditures of $19.1 million, $55.6 million and $126.9 million for 2015, 2014 and 2013, respectively. The decrease in capital expenditures from 2013 to 2014 was due to the completion of Phase I of the Ho-Ho expansion and reversal project. Phase II and III of the project were completed in 2014 resulting in the decrease in capital expenditures from 2014 to 2015.

A summary of our capital expenditures for 2015, 2014 and 2013, is shown in the table below (in millions):  

 

 

⁽¹⁾ Prior-period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

We expect total capital expenditures to be approximately $60.4 million for 2016.

We expect Zydeco’s maintenance capital expenditures, which are asset integrity projects in nature, to be approximately $19.6 million for 2016, of which approximately $12.8 million is to replace a two-mile section of a 22-inch diameter pipe under the Atchafalaya River and Bayou Shaffer. In connection with the Zydeco Acquisition, SPLC agreed to indemnify the Partnership against the Partnership’s proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2015 with respect to this pipeline replacement project. The remaining capital expenditures of approximately $6.8 million for 2016 are related to upgrades at Houma and Port Neches. We expect Auger and Lockport’s maintenance capital expenditures, which are asset integrity projects in nature, to be approximately $10.0 million for 2016.  This includes $4.8 million for electrical and storm water upgrades at Lockport, and $5.2 million for control system upgrade and personnel escape pods at Ship Shoal 28 for Auger.

We expect Zydeco’s expansion capital expenditures to be $30.1 million for Houma upgrades and expansion, including electrical transformer, pump stations, new connections, land purchases and possible pipeline expansion.  We expect expansion capital expenditures for Lockport to be $0.7 million for a pipeline connection for 2016. With the exception of the Zydeco pipeline replacement project, we anticipate that both maintenance and expansion capital expenditures for the remainder of the year will be funded primarily with cash from operations.

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Contractual Obligations

A summary of our contractual obligations, as of December 31, 2015, is shown in the table below (in millions):

 

 

⁽¹⁾ Includes $41.6 million in interest, $22.8 million in principal and $11.3 million in executory costs.

⁽²⁾ See Note 9 – Related Party Debt in the Notes to Consolidated Financial Statements in Part II, Item 8 of this report for additional information.

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 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 effective December 1, 2015. Upon the in-service date, which is expected to occur during the second quarter of 2016, our monthly lease payment will be $0.4 million. In the eighteenth month after the in-service date, actual fixed and variable costs will be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease will be adjusted accordingly and this adjustment will be effective for the remainder of the lease. The imputed interest rate on the capital portion of the lease is 15.7%.

Off-Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements that would result in off-balance sheet liabilities.

Inflation

Inflation did not have a material impact on our results of operations in 2015.

Environmental Matters and Compliance Costs

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to obtain permits or other approvals to conduct regulated activities, remediate environmental damage from any discharge of petroleum or chemical substances from our facilities or install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints. Please see FERC and State Common Carrier Regulations Part I, Items 1 and 2. Business and Properties.

Future additional expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our assets. These requirements could result in additional compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity.

If we do not recover these expenditures through the rates and other fees we receive for our services, our operating results will be adversely affected. We believe that 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.

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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 have evaluated the accounting policies used in the preparation of the consolidated financial statements of Shell Midstream Partners, L.P. and related notes thereto and believe those policies are reasonable and appropriate.

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, revenue recognition, allowance oil, and environmental and legal obligations. 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

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 (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 $21.6 million, $18.4 million and $13.7 million for 2015, 2014 and 2013, 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 to the consolidated financial statements and notes thereto included elsewhere in this report.

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. Our asset retirement obligations relate to our exclusive right of use of a portion of the Garden Banks 128 “A” Platform (GB 128A), where we operate facilities relating to the Auger pipeline system. We have determined that a significant portion of our assets utilizing GB 128A have an indeterminate life, and as such, the fair values of those associated retirement obligations are not reasonably estimable. Our right of use agreement provides that we pay our share of the GB 128A decommissioning costs when and if that platform ceases operation. Although the individual assets that constitute Zydeco will be replaced as needed, the pipeline will continue to exist for an indefinite useful life. As such, there is uncertainty around the timing of those asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligation. We have recognized asset retirement obligations of $1.3 million as of December 31, 2015 and 2014.

Revenue Recognition

We generate the majority of our revenue under long-term transportation agreements by charging fees for the transportation of crude oil and refined products through our pipelines. 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.

All of Lockport’s tank capacity is leased under long-term guaranteed storage tank services and throughput agreements by which monthly fees are charged.

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As a result of FERC regulations, revenue 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 $1.7 million and $0.6 million for third and related-party payables, respectively, for potential refunds as of December 31, 2015, and no reserves for potential refunds as of December 31, 2014.

Our ship-or-pay contracts provide a minimum volume commitment to our customers. Under these contracts, our customers agree to ship a minimum volume of crude oil on our pipeline system. If shippers do not meet the minimum contracted volume commitments under our ship-or-pay contracts, we receive deficiency payments as described in — How We Generate Revenue.

Cash collected from customers for shortfalls under these agreements are recorded as deferred revenue. We recognize deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have been satisfied or expired.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or “PLA.” PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The 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 convert that product to cash several times per year at prevailing market prices to a related party.

Allowance Oil

A PLA factor per barrel is incorporated into applicable crude oil tariffs to cover evaporation and other losses in transit. Allowance oil represents the net difference between the tariff PLA volumes and the actual volumetric losses. Our allowance oil is valued at cost using the average market price of the relevant type of crude oil during the month product was transported.

Environmental and Legal Obligations

We consult with various professionals to assist us in making estimates relating to environmental costs and legal proceedings. We accrue an expense when we determine that it is probable that a liability has been incurred and the amount is reasonably estimable. While we believe that the amounts recorded in the accompanying consolidated financial statements related to these contingencies are based on the best estimates and judgments available, the actual outcomes could differ from our estimates. Additional information about certain legal proceedings and environmental matters appears in Note 14 — Commitments and Contingencies in Part II, Item 8 to the consolidated financial statements and notes thereto included elsewhere in this report.

Recent Accounting Pronouncements

Please read Note 2 — Summary of Significant Accounting Policies — Recent Accounting Pronouncements in Part II, Item 8 of this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market risk is the risk of loss arising from adverse changes in market rates and prices. Since 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 have limited direct exposure to risks associated with fluctuating commodity prices.

Our long-term transportation agreements and tariffs for crude oil shipments include a product loss allowance. The 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 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% and 12.8% of our total revenue in 2015 and 2014, is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices. As a result, the revenue we realize under our loss allowance provisions will increase or decrease as a result of changes in 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.

Debt that we incur under our revolving credit facility that bears interest at a variable rate will expose us to interest rate risk.  We do not currently intend to enter into any interest rate hedging agreements, but will continue to monitor interest rate exposure.

 

 

 

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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

SHELL MIDSTREAM PARTNERS, L.P.

INDEX TO FINANCIAL STATEMENTS

 

 

 

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Unitholders of Shell Midstream Partners, L.P.

 

In our opinion, based on our audits and the reports of other auditors, the accompanying consolidated balance sheets and the related consolidated statements of income, changes in equity and cash flows present fairly, in all material respects, the financial position of Shell Midstream Partners, L.P. (the “Partnership”) and its subsidiaries at December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America.  Also in our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Report on Internal Control over Financial Reporting appearing under Item 9A.  Our responsibility is to express opinions on these financial statements and on the Partnership's internal control over financial reporting based on our audits (which was an integrated audit in 2015).  We did not audit the financial statements of Bengal Pipeline Company LLC (“Bengal”), a 49% equity investment of the Partnership, as of and for the year ended December 31, 2015, which is reflected in the consolidated financial statements of the Partnership as an equity method investment of $75.6 million at December 31, 2015 and income from equity investments of $20.8 million for the year ended December 31, 2015. We also did not audit the financial statements of Poseidon Oil Pipeline Company, L.L.C. (“Poseidon”), a 36% equity investment of the Partnership, as of and for the year ended December 31, 2015, which is reflected in the consolidated financial statements of the Partnership as an equity method investment of $25.4 million at December 31, 2015 and income from equity investments of $16.1 million for the year ended December 31, 2015.  The financial statements of Bengal and Poseidon were audited by other auditors whose reports thereon have been furnished to us, and our opinion on the financial statements expressed herein, insofar as it relates to the amounts included for Bengal and Poseidon, is based solely on the reports of the other auditors.  We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).  Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.  Our audits of the financial statements included 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, and evaluating the overall financial statement presentation.  Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.  Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinions.

 

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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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/ PricewaterhouseCoopers LLP

Houston, Texas

February 26, 2016

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Managers and Members

Bengal Pipeline Company LLC

We have audited the accompanying balance sheet of Bengal Pipeline Company LLC as of December 31, 2015 and the related statements of income, members’ equity and cash flows for the year then ended (not presented separately herein). 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 auditing standards generally accepted in the United States and in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s 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, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Bengal Pipeline Company LLC at December 31, 2015, and the results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Atlanta, Georgia

February 12, 2016

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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 accompanying balance sheet of Poseidon Oil Pipeline Company L.L.C. (the "Company") as of December 31, 2015, and the related statements of operations, cash flows, and members' equity for the year ended December 31, 2015. 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). 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 financial position of Poseidon Oil Pipeline Company L.L.C. as of December 31, 2015, and the results of its operations and its cash flows for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

February 19, 2016

 

 

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SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

 

 

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

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SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

 

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations from January 1, 2015 through September 30, 2015.

⁽²⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

The accompanying notes are an integral part of the consolidated financial statements.

 

 

 

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SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS  

 

 

 

⁽¹⁾ The 2015 financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations from January 1, 2015 through September 30, 2015.

⁽²⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

 

The accompanying notes are an integral part of the consolidated financial statements.

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SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

 

 

⁽¹⁾ Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

 

The accompanying notes are an integral part of the consolidated financial statements.

 

 

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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. Prior-period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

 

 

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 on March 19, 2014 to own and operate assets, including certain assets received from Shell Pipeline Company LP (“SPLC”). We conduct our operations through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”). Our general partner is Shell Midstream Partners GP LLC (“general partner”).  References to “Shell” refer collectively to Royal Dutch Shell plc (“RDS”) and its controlled affiliates, other than us, our subsidiaries and our general partner.

Description of Business

We are a fee-based, growth-oriented master limited partnership formed by Shell to own, operate, develop and acquire pipelines and other midstream assets. Our assets consist of interests in entities that own crude oil and refined products pipelines serving as key infrastructure to transport onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. As of December 31, 2015, we own interests in four crude oil pipeline systems, two refined products systems and a crude storage terminal. The crude oil pipeline systems, which are held by Zydeco Pipeline Company LLC (“Zydeco”), Mars Oil Pipeline Company (“Mars”), Poseidon Oil Pipeline Company LLC (“Poseidon”) and the Auger Pipeline System (“Auger”), are strategically located along the Texas and Louisiana Gulf Coast and in the Gulf of Mexico. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal Pipeline Company LLC (“Bengal”) and Colonial Pipeline Company (“Colonial”), connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York. The crude storage terminal, which is held by the Lockport Terminal (“Lockport”), is located southwest of Chicago and serves Midwest refineries.

On July 1, 2014, SPLC formed a wholly owned subsidiary named Zydeco. In anticipation of our initial public offering (“IPO”) of common units by the Partnership, SPLC contributed the fixed assets and certain agreements of the crude oil pipeline system from Houston, Texas to Houma, Louisiana (Ho-Ho, now referred to as “Zydeco pipeline” or “Zydeco pipeline system”) and other related fixed assets of SPLC to Zydeco. The working capital balances of $1.8 million related to Zydeco pipeline as of June 30, 2014 were not contributed from SPLC to Zydeco. On November 3, 2014, we completed our IPO and our common units trade on the New York Stock Exchange under the symbol “SHLX.”

In preparation for its sale of the Auger and Lockport businesses to us (the “Shell Auger and Lockport Operations” or “Auger and Lockport”), on October 1, 2015, SPLC contributed all but the working capital of Auger and Lockport to Pecten Midstream LLC (“Pecten”), a wholly owned subsidiary of SPLC. On November 11, 2015 (effective October 1, 2015), we acquired a 100.0% interest in Pecten from SPLC for $390.0 million. We funded this acquisition with a combination of a public issuance of common units, the issuance of additional general partner units to our general partner, borrowings under our 364-Day Revolver and cash on hand.

As of December 31, 2015, we own a 100.0% interest in Pecten, a 62.5% interest in Zydeco, a 28.6% interest in Mars, a 36.0% interest in Poseidon, a 49.0% interest in Bengal and a 3.0% interest in Colonial. Zydeco is consolidated within our consolidated financial statements as a subsidiary. We obtained control of this affiliate via a voting agreement with SPLC through which we have voting power over the ownership interest retained by SPLC in Zydeco. The 37.5% ownership interest in Zydeco retained by SPLC is reflected as noncontrolling interest in our consolidated financial statements. The ownership of Pecten is consolidated within our consolidated financial statements as a subsidiary. We account for each of our investments in Mars, Bengal and Poseidon using the equity method of accounting, and we account for our investment in Colonial using the cost method of accounting.

We generate the majority of our revenue under long-term agreements by charging fees for the transportation and storage of crude oil and refined products through our pipelines and storage tanks. We do not engage in the marketing and trading of any commodities. Our operations consist of one reportable segment.

Basis of Presentation

Our consolidated financial statements include all majority owned and non-majority owned 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

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.

The acquisition of Pecten was a transfer of a business between entities under common control, which requires it to be accounted for as if the transfer had occurred at the beginning of the period of transfer, with prior periods retrospectively adjusted to furnish comparative financial information. Accordingly, the accompanying financial statements and notes have been retrospectively adjusted to include the historical results and financial position of the Shell Auger and Lockport Operations prior to the effective date of the acquisition. The additional acquisitions of interests in Zydeco, Colonial and Poseidon, all made in 2015, represented transfers of assets. Accordingly, these assets are included in the financial statements prospectively from the effective date of each acquisition. See Note 3 – Acquisitions for additional information.

 

The consolidated financial statements for the periods below were derived from the financial statements and accounting records of SPLC and Shell.  Our predecessor refers to our operations prior to the IPO. Specifically, our predecessor for accounting purposes (“Predecessor”) comprises the following:

provided, however, the financial results of Ho-Ho and Zydeco have been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

We refer to the Shell Auger and Lockport Operations for the period from November 3, 2014 through September 30, 2015 as “the Shell Auger and Lockport Predecessor.” We refer to our Predecessor and the Shell Auger and Lockport Predecessor collectively as our “Predecessors.”

Effective October 1, 2015, we acquired a business from SPLC, the Shell Auger and Lockport Operations, which we consolidate. The results of our Predecessors also include the operations of this business prior to October 1, 2015. These statements reflect the consolidated historical results of operations, financial position and cash flows as if the Predecessors’ business and the Shell Auger and Lockport Operations business had been consolidated entities for all periods prior to the effective dates of acquisition, November 3, 2014 and October 1, 2015.

Expense Allocations. The consolidated statements of income also include expense allocations to our Predecessor, as retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations, prior to July 1, 2014, and to the Shell Auger and Lockport Predecessor for the period from July 1, 2014 through September 30, 2015, for certain functions performed by SPLC and Shell during such periods. Such costs were charged to our Predecessor and 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 by our Predecessor during the periods presented. Nevertheless, the consolidated financial statements may not include all of the expenses that would have been incurred as a separate, publicly-traded company during the periods prior to November 3, 2014 and may not reflect our consolidated statements of income and cash flows as a separate, publicly-traded company during the periods prior to November 3, 2014.

Beginning from July 1, 2014, Zydeco, our Predecessor, 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 no longer receive allocated corporate expenses from SPLC. We will continue to receive direct and allocated field and regional expenses from SPLC including payroll expenses not covered under the operating and 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. See details of related party transactions in Note 4 — Related Party Transactions.

Cash. Prior to the contribution of fixed assets and certain agreements on July 1, 2014, regarding Zydeco, and October 1, 2015 regarding the Shell Auger and Lockport Operations, the cash generated and used by our operations was deposited to SPLC’s centralized account which was comingled with the cash of other pipeline entities controlled by SPLC. SPLC funded our operating and 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 July 1, 2014, regarding Zydeco, and October 1, 2015, regarding the Shell Auger and Lockport Operations. We reflected the cash generated by our operations and expenses paid by SPLC on behalf of our operations as Net contributions from (distributions

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

to) Parent within the accompanying consolidated statements of changes in equity and consolidated statements of cash flows. On July 1, 2014, regarding Zydeco, and October 1, 2015, regarding the Shell Auger and Lockport Operations, we established 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.

All financial information represents the consolidated statements of income, balance sheets and cash flows accordingly:

The Partnership generally accounts for investments in 20.0% to 50.0%-owned affiliates, and investments in less than 20.0%-owned affiliates where it has the ability to exercise significant influence, under the equity method. We own a 100.0% interest in Pecten, a 62.5% interest in Zydeco, a 28.6% interest in Mars, a 49.0% interest in Bengal, a 36.0% interest in Poseidon and a 3.0% interest in Colonial. Accordingly, the consolidated historical financial statements for the Partnership reflect the consolidation of Pecten (Shell Auger and Lockport Operations) and Zydeco (100.0%), and the investments in Mars, Bengal and Poseidon using the equity method of accounting. Our investment in Colonial is accounted for as a cost method investment.

Post-IPO Periods

On November 3, 2014, we completed our IPO of 46,000,000 common units (including 6,000,000 common units issued pursuant to the exercise of the underwriters’ over-allotment option). The Partnership received net proceeds of $1,011.7 million from the sale of 46,000,000 common units, after deducting underwriter discounts, commissions, structuring fees and other offering expenses of $46.3 million. At the completion of the IPO, SPLC owned 21,475,068 common units and 67,475,068 subordinated units, representing an aggregate 64.6% limited partner interest.  SPLC also owned a 100.0% interest in our general partner, which in turn owned 2,754,084 general partner units, representing a 2.0% general partner interest.

References to the Partnership or other expressions defined above for time periods beginning November 3, 2014 refer to the post-IPO accounting periods of Shell Midstream Partners, L.P. Prior period financial information has been retrospectively adjusted for the acquisition of the Shell Auger and Lockport Operations.

On May 18, 2015, the Partnership completed the sale of 7,692,308 common units representing limited partner interests (the “Common Units”) to unaffiliated third parties in a private placement (the “Private Placement”) for approximately $297.4 million net proceeds ($300.0 million of gross proceeds less $2.6 million of placement agent fees and other offering costs) and issued 156,986 general partner units to our general partner to maintain its 2.0% general partner interest.

On November 17, 2015, the Partnership completed the sale of 9,200,000 common units representing limited partner interests to unaffiliated third parties in a public offering (the “Offering”) for approximately $296.8 million net proceeds ($299.4 million of gross proceeds less $2.6 million of underwriters’ discount and other offering costs). The Partnership also issued 187,755 general partner units to our general partner to maintain its 2.0% general partner interest.

Upon the closing of the offering on November 17, 2015, SPLC’s wholly-owned subsidiary, Shell Midstream LP Holdings LLC, owned 21,475,068 common units and 67,475,068 subordinated units in the Partnership, representing an aggregate 57.4% limited partner interest. SPLC also owned a 100.0% interest in Shell Midstream Partners GP LLC, which in turn owned 3,098,825 general partner units, representing a 2.0% general partner interest, and all of the incentive distribution rights in the Partnership.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

2. Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include all subsidiaries where the Partnership has 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. We own 62.5% of the ownership interest in Zydeco. We record a noncontrolling interest for the 37.5% ownership interest in Zydeco retained by SPLC. We obtained control of Zydeco via the voting agreement between SPLC and us under which we have voting power over the ownership interests retained by SPLC in Zydeco. On November 17, 2015, the Partnership acquired 100.0% of the ownership interest in Pecten, with an effective date of October 1, 2015. Our historical financial statements have been retrospectively adjusted to reflect the results of operations, financial position, and cash flows of the Shell Auger and Lockport Operations prior to the effective date of the acquisition, as if we owned the business for all periods presented since this was a common control transaction.

 

Regulation

Certain businesses are subject to regulation by various authorities including, but not limited to the Federal Energy Regulatory Commission (“FERC”). Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers.

Net Parent Investment

In the accompanying consolidated balance sheets, Net Parent Investment represents SPLC’s historical investment in us, our accumulated net earnings through the date which we obtained control of the respective subsidiaries, and the net effect of transactions with, and allocations from, SPLC and Shell Oil Company. Retrospectively adjusted financial information from prior to the acquisition of the Shell Auger and Lockport Operations is included in Net Parent Investment.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported 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 their historical costs. 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 that excess is treated as a capital contribution from our General Partner. 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.

Revenue Recognition

Our revenues are primarily generated from crude oil transportation services and also storage services. In general, we recognize revenue from customers when all of the following criteria are met: (1) persuasive evidence of an exchange arrangement exists; (2) delivery or storage has occurred or services have been rendered; (3) the price is fixed or determinable; and (4) collectability is reasonably assured. We record revenue for crude oil transportation and storage services over the period in which they are earned (i.e., either physical delivery or storage of product has taken place or the services designated in the contract have been performed). We accrue revenue based on services rendered but not billed for that accounting month. Additionally, we provide crude storage rental services to third parties and related parties under long-term contracts.

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SHELL MIDSTREAM PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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, 2015 and 2014.

Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on a 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 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. 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.

Cash collected from customers for shortfalls under these agreements are recorded as deferred revenue. The Partnership recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the transportation of future excess volumes of crude oil, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the FERC-approved transportation services agreement. Because the expiration of a customer’s right to utilize shortfall payments is twelve months or less, we classify deferred revenue as a short term liability. Deferred revenue balance was $6.2 million and $20.0 million as of December 31, 2015 and 2014, respectively.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or “PLA.” PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The 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 an allowed level, and we convert that product to cash several times per year at prevailing market prices to a related party.

Revenues for the indicated years comprise the following:

 

 

Cash and cash equivalents

Cash and cash equivalents comprise cash on deposit at banks.

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, 2015 and 2014, our allowance for doubtful accounts was not material.

Allowance Oil

A PLA factor per barrel is incorporated into applicable crude oil tariffs to cover evaporation and other loss in transit. Allowance oil represents the net difference between the tariff PLA volumes and the actual volumetric losses. Our allowance oil is valued at cost using the average market price of the relevant type of crude oil during the month product was transported.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

As of December 31, 2015 and 2014, allowance oil on the balance sheet was $4.2 million and $4.1 million, respectively. Gains and losses from the conversion of allowance oil to cash and gains and losses from pipeline operations that relate to allowance oil are recorded in Operations and maintenance expenses in the accompanying consolidated statements of income. During 2014, we made a sale of allowance oil at prevailing market prices to a Shell affiliate. In 2015, we made multiple sales of allowance oil to third parties and Shell affiliates. See Note 4 — Related Party Transactions for more details.

Equity Method Investments

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. 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, and the amount of the write-down is included in net income. 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.  

The following table shows our net purchase cost adjustment and amortization of such regarding our equity method investments as of 2015 and 2014:

 

 

⁽¹⁾ Our equity investment balance is recorded net of a deferred gain upon the formation of the joint venture in Bengal.

⁽²⁾  We acquired an equity interest in Poseidon on July 1, 2015. For additional information regarding this transaction, see Note 3 - Acquisitions.

 

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 cost 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 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 loss (gain) from 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 market declines that are believed to be other than temporary, 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 our management’s estimate of forecasted undiscounted future cash flows associated with the asset to the asset’s net book value. If the net book value exceeds our estimate of forecasted undiscounted cash flows, an impairment is calculated as the amount the net book value exceeds the estimated discounted future cash flows associated with the asset. We determined that there were no asset impairments in 2015, 2014 or 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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.  Income taxes (benefit) expense for 2015, 2014, and 2013 were $(0.1) million, $0.2 million and $0.1 million, respectively.

Cost Method Investment

We account for investments in entities we do not control or account for under the equity method under the cost method. Cost method investments are reported as other assets in our consolidated balance sheets. Our cost investment included a 3.0% interest in Colonial with a balance of $6.2 million as of December 31, 2015, and a 1.612% interest in Colonial with a balance of $3.7 million as of December 31, 2014.

Asset Retirement Obligations

Asset retirement obligations represent legal and constructive obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset. We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses at fair value on a discounted basis when they are incurred and can be reasonably estimated. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities increase due to the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when settled at the time the asset is taken out of service.

Our asset retirement obligations relate to our exclusive right of use of a portion of the Garden Banks 128 “A” Platform (GB 128A), where we operate facilities relating to the Auger pipeline system. Our right of use agreement provides that we pay our share of the GB 128A decommissioning costs when and if that platform ceases operation. We have determined that a significant portion of our assets utilizing GB 128A have an indeterminate life, and as such, the fair values of those associated retirement obligations are not reasonably estimable. These assets include offshore pipelines pump and meter stations whose retirement dates 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, therefore we are unable to estimate retirement dates that would result in asset retirement obligations.

Asset retirement obligations are adjusted each period for liabilities incurred or settled during the period, accretion expense and any revisions made to the estimated cash flows.

A reconciliation of changes in asset retirement obligations for 2015 and 2014 is as follows:

 

 

We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record. The demand for our pipelines depends on the ongoing demand to move crude oil through the system. Although individual assets will be replaced as needed, our pipelines will continue to exist for an indefinite useful life. As such, there is uncertainty around the timing of any asset retirement activities. As a result, with the exception of the platform related asset retirement obligations stated above, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligations for our remaining assets as of December 31, 2015 and 2014.

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 to us 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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 4 — 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 reasonably possible 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 lower end of the range. 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 expenditure through tariff rates charged to customers. We also expense costs that relate to an existing condition caused by past environmental incidents, which do not contribute to current or future revenue generation. We discount environmental liabilities to a net present value, and 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. We do not use regulatory accounting principles.

For 2015, 2014 and 2013, we incurred zero, $3.0 million and $13.6 million, respectively of environmental cleanup costs. Due to the formation of Zydeco via the contribution of fixed assets and certain agreements from SPLC, Zydeco was indemnified by SPLC against environmental cleanup costs for incidents that occurred prior to Zydeco’s formation on July 1, 2014. In 2013, the West Columbia pipeline segment experienced a breach in which approximately 940 barrels of oil released in the vicinity of the pipeline. During 2013, we incurred $12.1 million in costs primarily related to several large maintenance projects for the containment of this incident at the West Columbia pipeline. Our Predecessor disposed of the West Columbia pipeline in 2013. In addition, as a result of the contribution of Pecten from SPLC, SHLX was indemnified by SPLC against cleanup costs for incidents that occurred at Auger or Lockport prior to the contribution of Pecten on October 1, 2015. There were no environmental incidents related to Auger or Lockport during the periods presented. As of December 31, 2015 and 2014, we had no accruals for environmental clean-up costs. Refer to Note 4 — 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

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, accrued liabilities and revolving credit agreements approximate their carrying values due to their short term nature.  

Nonrecurring Fair Value Measurements — Fair value measurements are applied with respect to our nonfinancial assets and liabilities measured on a nonrecurring basis, which consist primarily of asset retirement obligations. Nonrecurring fair value measurements are also applied, when applicable, to determine the fair value of our long-lived assets.

Net income per limited partner unit

Net income per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the IPO 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. Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the period presented.

Comprehensive Income

We have not reported comprehensive income due to the absence of items of other comprehensive income in the periods presented.  

Recent Accounting Pronouncements

In April 2015, the FASB issued accounting standards update to Subtopic 835-30, Interest – Imputation of Interest to simplify the presentation of debt issuance costs. The amendments require that debt issuance costs related to a recognized debt liability be presented as a direct deduction from the carrying amount of that debt liability. These provisions are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

In April 2015, the FASB issued an accounting standards update to topic 260, Earnings Per Share to clarify the presentation of historical earnings per unit for periods prior to the effective date of a transfer of a business to a master limited partnership from the general partner accounted for as an transaction between entities under common control. The amendments in this update specify that for purposes of calculating historical earnings per unit under the two-class method, the earnings (losses) of a transferred business before the effective date of the transaction should be allocated entirely to the general partner. In that circumstance, the previously reported earnings per unit of the limited partners (which is typically the earnings per unit measure presented in the financial statements) would not change as a result of the transaction. Qualitative disclosures about how the rights to the earnings (losses) differ before and after the transaction occurs for purposes of computing earnings per unit under the two-class method are also required. These provisions are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. We have elected early adoption for the fiscal year and interim periods within 2015. As a result, earnings of acquired businesses prior to the effective date of each acquisition are not allocated to our unitholders in our earnings per unit calculations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In July 2015, the FASB issued accounting standards update to topic 330, Inventory to simplify the measurement of inventory. This amendment requires that inventory should be measured at the lower of cost and net realizable value. Net realizable value is the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This standard update becomes effective for fiscal years beginning after December 15, 2016, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

In August 2015, the FASB affirmed its earlier proposal to defer the effective date of the new revenue standard topic 606, Revenue from Contracts with Customers, for all entities by one year, to annual reporting periods beginning after December 15, 2017. The FASB also decided to permit early adoption, but not before the original public entity effective date of December 15, 2016. We are currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.

In August 2015, the FASB issued an accounting standards update to Subtopic 835-30, Interest – Imputation of Interest to allow for reporting entities to treat debt issuance costs related to line-of-credit arrangements as an asset and subsequently amortize ratably over the term of the line-of-credit arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. This accounting standard amends the standard issued in April 2015 in order to specify how to treat line-of-credit arrangements. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

In September 2015, the FASB issued accounting standards update to topic 805, Business Combinations to require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The adoption of this guidance will not have a material effect on our financial position or results of operations.

In February 2016, the FASB issued accounting standards update to topic 842, Leases, which requires lessees to recognize assets and liabilities for leases with lease terms greater than twelve months in the statement of financial position. 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. This provision is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.

 

 

3. Acquisitions

May 2015 Acquisition

On May 18, 2015, we acquired an additional 19.5% interest in Zydeco and an additional 1.388% interest in Colonial for $448.0 million in cash (the “May 2015 Acquisition”). The May 2015 Acquisition closed pursuant to a Purchase and Sale Agreement dated May 12, 2015 (“Purchase and Sale Agreement”) among the Operating Company, the Partnership and SPLC, and was effective on April 1, 2015, and is accounted for as a transaction between entities under common control. We have recorded this asset acquisition prospectively from the effective date. The Partnership funded the May 2015 Acquisition with $297.4 million from the net proceeds from the Private Placement, $80.0 million of cash on hand and $70.8 million in borrowings under our Five-Year Revolver (as defined below in Note 9 – Related Party Debt). In addition, SPLC contributed to the Partnership $6.1 million in exchange for 156,986 general partner units representing general partner interest. Total transaction costs of $0.5 million were incurred in association with the May 2015 Acquisition. The terms of the May 2015 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 accordance with the Purchase and Sale Agreement, SPLC agreed to reimburse us for our proportionate share of certain costs and expenses incurred by Zydeco after April 1, 2015 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 payment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

In connection with the May 2015 Acquisition we acquired book value of net assets under common control, which is included in our consolidated balance sheet, as follows:

 

 

⁽¹⁾ Book value of 1.388% additional interest in Colonial contributed by SPLC.

⁽²⁾ Book value of 19.5% additional interest in Zydeco from SPLC’s noncontrolling interest.

We recognized $392.6 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.

July 2015 Acquisition

July 1, 2015, Shell Oil Products US (“SOPUS”) conveyed to us its 36.0% interest in Poseidon (the “July 2015 Acquisition”) for $350.0 million in cash. The July 2015 Acquisition closed pursuant to the contribution agreement dated July 1, 2015 (the “Poseidon Contribution Agreement”) among the Operating Company, the Partnership and SOPUS and is accounted for as a transaction between entities under common control. We have recorded this asset acquisition prospectively from the effective date. Poseidon is a Delaware limited liability company formed in February 1996 to design, construct, own and operate a non-FERC regulated crude oil pipeline system located offshore Louisiana in the central region of the Gulf of Mexico. The July 2015 Acquisition was funded with borrowings of $100.0 million under our 364-Day Revolver and $250.0 million under our Five-Year Revolver. For additional information regarding these credit facilities, see Note 9 — Related Party Debt. We account for our interest in Poseidon using the equity method of accounting.

In connection with the July 2015 Acquisition we acquired book value of net assets under common control of $30.5 million which is included in Equity method investments in our consolidated balance sheet. We recognized $319.5 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.

November 2015 Acquisition

On November 17, 2015, we acquired 100.0% interest in Pecten, which holds the Shell Auger and Lockport Operations, for $390.0 million (the “November 2015 Acquisition”). The November 2015 Acquisition closed pursuant to the contribution agreement (the “Pecten Contribution Agreement”) among the Operating Company, the Partnership and SPLC, and became effective on October 1, 2015, and is accounted for as a transaction between entities under common control. The Partnership funded the November 2015 Acquisition with $297.1 million from the net proceeds of the Offering, $49.4 million of cash on hand and $37.4 million in borrowings under one of our revolving credit facilities. The remaining $6.1 million in consideration consisted of the issuance of 187,755 general partner units representing general partner interests to our general partner. Total transaction costs of $0.3 million were incurred in association with the November 2015 Acquisition. The terms of the November 2015 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. The Pecten Contribution Agreement contains customary representations, warranties and covenants of SPLC, the Partnership and Operating. SPLC, on the one hand, and the Partnership and Operating, on the other hand, have agreed to indemnify each other and their respective affiliates, officers, directors and other representatives against certain losses resulting from any breach of their representations, warranties or covenants contained in the Pecten Contribution Agreement, subject to certain limitations and survival periods.

In connection with the November 2015 Acquisition we acquired book value of net assets under common control which is included in our consolidated balance sheet, as follows:

 

 

⁽¹⁾ Historical carrying value of property, plant and equipment, net contributed by SPLC.

⁽²⁾ Historical carrying value of asset retirement obligation assumed by the Partnership.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

We recognized $290.0 million of consideration as a capital distribution to our general partner in accordance with our policy for common control transactions.

Retrospective adjusted information tables

The following tables present our financial position and our results of operations giving effect to the November 2015 Acquisition of Pecten. The results of Pecten prior to the effective date of the acquisition are included in “the Shell Auger and Lockport Operations” and the consolidated results are included in “Consolidated Results” within the tables below:

 

 

⁽¹⁾ The financial position of the Shell Auger and Lockport Operations Predecessor as of December 31, 2014.

 

      

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

⁽¹⁾ As previously reported in our Annual Report on Form 10-K for 2014.

⁽²⁾ Our Predecessors’ results of the Shell Auger and Lockport Operations from January 1, 2014 through December 31, 2014.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

⁽¹⁾  As previously reported in our Annual Report on Form 10-K for 2014.

⁽²⁾  Our Predecessor’s results of the Shell Auger and Lockport Operations from January 1, 2013 through December 31, 2013.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

 

⁽¹⁾ As previously reported in our Annual Report on Form 10-K for 2014.

⁽²⁾ Our Predecessors’ cash flows from/to the Shell Auger and Lockport Operations from January 1, 2014 through December 31, 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

 

⁽¹⁾ As previously reported in our Annual Report on Form 10-K for 2014.

⁽²⁾ Our Predecessor’s cash flows from/to the Shell Auger and Lockport Operations from January 1, 2013 through December 31, 2013.

 

 

4. 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.

Commercial Agreements

Omnibus Agreement

On November 3, 2014, in connection with the IPO and the acquisition of Zydeco, 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:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Under the Omnibus Agreement, certain costs are indemnified by SPLC. Both, the legal and environmental indemnifications are subject to individual $0.5 million deductibles, while we have an aggregate limit of $15.0 million. As of December 31, 2015 we have filed two claims for indemnification.

Indemnification for any unknown environmental liabilities is limited to liabilities due to occurrences prior to the closing of the IPO and that are identified before the third anniversary of the closing of the IPO.  Indemnification for losses related to right-of-way and permits, retained assets or litigation matters (other than currently pending legal actions) are limited to events reported within one year of the date of the IPO.  SPLC will also indemnify us for tax liabilities which are identified prior to the date that is 60 days after the expiration of the statute of limitations applicable to such liabilities.  We have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets (other than any environmental liabilities for which SPLC is specifically required to indemnify us as described above). There is no limit on the amount for which we will indemnify SPLC under the Omnibus Agreement.

Mars has incurred maintenance expense for an underground cavern integrity project including inspections, plug and abandonment, installations and integrity tests to return the Mars Cavern 4 to service. During 2015, we received reimbursements from SPLC related to the indemnification for the Partnership’s share of these expenses which are included in other contributions from Parent.

Zydeco has incurred general and administrative expenses including expert fees related to a legal matter regarding FERC tariff rates and has also recognized an estimated settlement provision. Refer to Note 14 – Commitments and Contingencies – Legal Proceedings for additional information. During 2015, we received reimbursements from SPLC related to the indemnification for the Partnership’s share of these expenses which are included in other contributions from Parent.

Acquisition Agreements

See the description of the Purchase and Sale Agreement relating to the May 2015 Acquisition, the Poseidon Contribution Agreement relating to the July 2015 Acquisition and the Pecten Contribution Agreement relating to the November 2015 Acquisition as further described in Note 3 – Acquisitions.  

Formation of Zydeco

In connection with the IPO and the formation of Zydeco, the Partnership has entered into various agreements with SPLC and Shell.

On July 1, 2014, in conjunction with its formation, Zydeco entered into a contribution agreement (the “Contribution Agreement”) and the Management Agreement with SPLC. Pursuant to the Contribution Agreement, Zydeco reimburses SPLC for capital expenditures incurred by SPLC on behalf of Zydeco subsequent to November 3, 2014. The Management Agreement requires Zydeco to pay SPLC an annual management fee for general and administrative services.

Tax Sharing Agreement

Zydeco has entered into a tax sharing agreement with an affiliate of Shell pursuant to which Zydeco has agreed to reimburse Shell for state and local franchise taxes attributable to Zydeco’s activity that is reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under the agreement equal the amount of tax Zydeco would be required to pay if it were to file a consolidated, combined or unitary tax return separate from Shell. Shell will compute and invoice Zydeco for the reimbursement amount within 90 days of Shell filing the combined or unitary tax return on which Zydeco’s activity is included. Zydeco may be required to make prepayments toward the reimbursement amount to the extent that Shell is required to make estimated tax payments.

Transfer of the Shell Auger and Lockport Operations from the Parent to the Partnership

During 2015, we recognized a $290.0 million capital distribution to our general partner for consideration paid to acquire the Shell Auger and Lockport Operations under common control. For additional information regarding this transaction, see Note 3 – Acquisitions.

Maintenance expense and capital expenditures for certain projects associated with the Lockport Terminal have been incurred. These projects improve the existing drainage system to eliminate the crossing of storm water between the Lockport Terminal and adjacent properties. In addition, these projects include inspections and tank repairs of a storage tank.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Under the Pecten Contribution Agreement, SPLC has agreed to reimburse us for the maintenance expense and capital expenditures related to these projects. During 2015, we recognized these reimbursements as other contributions from Parent.

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.

Other Related Party Balances

Other related party balances consist of the following as of the dates indicated:

 

 

⁽¹⁾  Accounts payable – related parties reflects amounts owed to SPLC for reimbursement of third-party expenses incurred by SPLC for our benefit.

⁽²⁾  Accrued liabilities -- related parties reflects $1.3 million accrued interest, $1.2 million fuel accrual, $0.6 FERC accrual and $0.5 million other  accrued liabilities.

Related Party Revolving Credit Facilities

We have entered into two revolving credit facilities with Shell Treasury Centre (West) Inc. (“STCW”), an affiliate of Shell, the Five-Year Revolver and the 364-Day Revolver. Zydeco has also entered into the Zydeco Revolver with STCW. For additional information regarding these credit facilities, see Note 9 – Related Party Debt.

Related Party Revenues and Expenses

We provide crude oil transportation and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business and the services are based on the same terms as those provided to third parties. Our transportation revenue and storage services revenue from related parties for 2015, 2014 and 2013 is disclosed in Note 2- Summary of Significant Accounting Policies - Revenue Recognition.

In 2015, we recorded a $0.1 million gain in operations and maintenance from converting excess allowance oil to cash by selling to multiple customers, including Shell affiliates. In November 2014, we recorded a $0.4 million loss in operations and maintenance – related parties from converting excess allowance oil to cash by selling the allowance oil to an affiliate of Shell.  

As of December 31, 2014 the amount of the Distribution payable to SPLC was $11.9 million, of which $6.8 million relates to Zydeco. Such amounts were paid to SPLC during 2015.

For a discussion of services performed by SPLC and Shell on our behalf, see Note 1 – Description of the Business and Basis of Presentation – Basis of Presentation. During 2015, 2014 and 2013, we were allocated $5.8 million, $9.9 million and $13.8 million, respectively, of indirect general corporate expenses incurred by SPLC and Shell which are included within general and administrative expenses in the accompanying consolidated statements of income.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Beginning July 1, 2014, Zydeco entered into the Management Agreement with SPLC under which SPLC provides general management and administrative services to us. We no longer receive allocated corporate expenses from SPLC or Shell. We will continue to receive direct and allocated field and regional expenses, including payroll expenses not covered under the Management Agreement. In addition, beginning October 1, 2015, Pecten entered into an operating and management agreement under which we receive direct and allocated field and regional expenses from SPLC. These expenses 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. For 2015 and the six months ended December 31, 2014, the management fee charged by SPLC under the Management Agreement was $7.4 million and $3.5 million, respectively.

Prior to the IPO, we were covered by the insurance policies of SPLC. Subsequent to the IPO, the majority of our coverage is provided by Shell with the remaining coverage by third-party insurers. The related party portion of insurance expense in 2015, 2014 and 2013 was $3.6 million, $5.2 million and $4.4 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:

 

 

⁽¹⁾ For 2015 and 2014, we incurred $7.4 million and $3.5 million, respectively, under the Management Agreement and $8.5 million and $1.4 million, respectively, under the Omnibus Agreement for general and administrative services.

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 2015, 2014 and 2013 was $3.0 million, $3.2 million and $4.0 million, respectively. Our share of defined contribution benefit plan costs for 2015, 2014 and 2013 was $1.3 million, $1.3 million and $1.5 million, respectively. Pension and defined contribution benefit plan expenses 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.

Share-based compensation

Shell’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). The Performance Share Plan (“PSP”) was introduced in 2005 by Shell. Conditional awards of RDS shares are made under the terms of the 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. For the PSP awards made prior to 2010, the other half of the award was linked to the relative total shareholder return over the period compared with four main competitors of RDS. For awards made in 2010 and onwards, 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 these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from Shell related to Ho-Ho (for the periods prior to June 30, 2014) and related to Pecten (for the periods prior to October 1, 2015). Beginning July 1, 2014, we did not receive any allocated share-based compensation for Ho-Ho, and beginning October 1, 2015, we did not receive any allocated share –based compensation for Pecten. Share-based compensation expense is included in general and administrative expenses in the accompanying consolidated statements of income.  These costs totaled less than $0.1 million, approximately $0.2 million and $0.3 million for 2015, 2014 and 2013, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Equity and Cost Method Investments

We have equity and cost method investments in entities that own certain of our assets, including Mars, Bengal, Poseidon and Colonial. SPLC also owns interests in some of these entities. 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 other contributions from our Parent in 2015:

 

 

⁽¹⁾ The JV partner agreed to pay us $4.5 million in order to secure a waiver of rights of refusal from SOPUS and us permitting the JV partner to acquire another owner’s interest in Poseidon.

⁽²⁾ Contractual reimbursement by SPLC pursuant to the Purchase and Sale Agreement for our proportionate share of costs and expenses incurred by Zydeco after April 1, 2015 regarding a directional drilling project.  

⁽³⁾ Environmental indemnification by SPLC under the Omnibus Agreement regarding maintenance expense for Mars underground cavern integrity project including inspections, plug and abandonment, installations and integrity tests to return the Mars Cavern 4 to service.

⁽⁴⁾ Legal indemnification by SPLC under the Omnibus Agreement for expenses and settlement payments relating to the Zydeco FERC rate case.

⁽⁵⁾ Contractual reimbursement by SPLC pursuant to the Pecten Contribution Agreement regarding costs and expenses for maintenance projects     at Lockport.

⁽⁶⁾ Total contributions include $11.1 million of cash received and $1.8 million contribution receivable from our Parent.

 

 

5. Accounts Receivable

Accounts receivable from third parties comprise the following as of the dates indicated:

 

 

 

6. Equity Method Investments

As of December 31, 2015, our equity method investments consist of 28.6% interest in Mars, 49.0% interest in Bengal and 36.0% interest in Poseidon.

Equity investments in affiliates comprise the following as of the dates indicated:

 

 

⁽¹⁾ We acquired an equity interest in Poseidon on July 1, 2015. For additional information regarding this transaction, see Note 3 - Acquisitions.

 

Our equity investments in affiliates balance was affected by the following during the periods indicated:

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⁽¹⁾ Distributions received in excess of our income from equity investments is shown as a return of investment in our consolidated statements of cash flows.

⁽²⁾ Income from equity investments in excess of distributions is shown as a reduction to cash flows from operating activities in our consolidated statements of cash flows.

 

Summarized Financial Information

The following presents aggregated selected balance sheet and income statement data for our equity method investments (on a 100.0% basis):

 

 

⁽¹⁾ Interest in Poseidon was acquired by the Partnership on July 1, 2015. For 2015, Poseidon total revenue, total operating expenses and operating income (on a 100% basis) was $123.7 million, $28.6 million, and $95.1 million, respectively.

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⁽¹⁾ Interests in Mars and Bengal were acquired by the Partnership on November 3, 2014. For 2014, Mars total revenue, total operating expenses and operating income (on a 100% basis) was $160.5 million, $73.0 million, and $87.4 million, respectively, and Bengal total revenue, total operating expenses and operating income (on a 100% basis) was $65.9 million, $27.2 million, and $38.7 million, respectively.

 

 

 

7. Property, Plant and Equipment

Property, plant and equipment consist of the following as of the dates indicated:

 

 

Depreciation expense on property, plant and equipment of $21.6 million, $18.4 million and $13.7 million is included in cost and expenses in the accompanying consolidated statements of income for 2015, 2014 and 2013, respectively.

 

In August 2015, SPLC contributed an oil gathering line to the Shell Auger and Lockport Operations. This transaction resulted in an increase to Pipeline and equipment of $51.9 million, an increase to Accumulated depreciation of $51.5 million and an increase to Net Parent Investment of $0.4 million.

 

 

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8. Accrued Liabilities – Third Parties

Accrued liabilities – third parties consist of the following as of the dates indicated:

 

 

For a discussion of accrued liabilities – related parties, see Note 4 – Related Party Transactions.

 

 

9. Related Party Debt

Consolidated related party debt obligations comprise the following as of the dates indicated:

 

⁽¹⁾ As of December 31, 2015, availability under the $400.0 million Five-Year Revolver was $79.2 million. We pay interest of 0.19% on the unused capacity of the Five-Year Revolver.

⁽²⁾ As of December 31, 2015, availability under the $180.0 million 364-Day Revolver was $42.6 million. We pay interest of 0.12% on the unused capacity of the 364-Day Revolver.

⁽³⁾ As of December 31, 2015, availability under the $30.0 million Zydeco Revolver was $30.0 million. We pay interest of 0.23% on the unused capacity of the Zydeco Revolver.  

We paid interest of $2.7 million, approximately $0.1 million, and zero in 2015, 2014 and 2013 respectively.

Revolving Credit Facility Agreements

On November 3, 2014, the Partnership entered into the Five-Year Revolver, with an initial borrowing capacity of $300.0 million. Loans advanced under the initial agreement had up to a six-month term. On May 12, 2015, the Partnership and STCW amended and restated the Five-Year Revolver to increase the borrowing capacity amount to $400.0 million. In connection with the amendment and restatement of the Five-Year Revolver, the Partnership paid an issuance fee of $0.2 million.  The Five-Year Revolver, as amended and restated, provides for covenants such as restricting additional indebtedness above $600.0 million and requiring pari passu ranking with any new indebtedness, and contains customary events of default, such as nonpayment of principal when due, nonpayment of interest, fees or other amounts, violation of covenants, and cross-payment default (due to indebtedness in excess of $100.0 million).  

Borrowings under the Five-Year Revolver bear interest at the three-month LIBOR rate plus a margin. As of December 31, 2015, the interest rate for the Five-Year Revolver was 1.6%. The Five-Year Revolver also provides for customary fees, including administrative agent fees and commitment fees. Commitment fees began to accrue beginning on the date the Partnership entered into the Revolver agreement. The Five-Year Revolver was to originally mature on October 31, 2019.

On February 22, 2016, the Partnership and STCW again amended and restated the Five-Year Revolver to provide that loans advanced under the facility could have a term ending on or before its maturity date.  This amendment and restatement makes it possible for the Partnership, at its option, to borrow under the facility for periods in excess of the one-year maximum time period previously stipulated in the agreement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

During 2015, we borrowed $70.8 million to partially fund the May 2015 Acquisition, and an additional $250.0 million to partially fund the July 2015 Acquisition. There were $320.8 million outstanding borrowings as of December 31, 2015 and no outstanding borrowings as of December 31, 2014.

On June 29, 2015, in connection with the July 2015 Acquisition, the Partnership entered into a second revolving credit facility (the “364-Day Revolver”) with STCW as lender with an initial borrowing capacity of $100.0 million.

All other terms and conditions are materially the same as those of the Five-Year Revolver. Borrowings under the 364-Day Revolver bear interest at the three-month LIBOR rate plus a margin. As of December 31, 2015 the interest rate for the 364-Day Revolver was 1.4%. The 364-Day Revolver also provides for customary fees, including administrative agent fees and commitment fees. Commitment fees began to accrue beginning on the date the Partnership entered into the 364-Day Revolver agreement. The Partnership paid a credit facility issuance fee of $0.1 million.

On November 11, 2015, the Partnership and STCW amended and restated the 364-Day Revolver to increase the borrowing capacity amount from $100.0 million to $180.0 million. The Partnership also agreed to an additional issuance fee of $0.1 million paid within five business days. The 364-Day Revolver was amended to mature on November 10, 2016.

On February 22, 2016, the Partnership and STCW again amended and restated the 364-Day Revolver to extend its maturity to March 1, 2017.   All other terms and conditions of the agreement were unchanged.

As of December 31, 2015 and 2014, the amount of credit facility issuance costs in Other assets is $0.6 million and $0.5 million, respectively. For 2015 and 2014, interest and fee expenses were approximately $4.0 million and $0.1 million, respectively. There were $458.2 million outstanding borrowings as of December 31, 2015 and no outstanding borrowings as of December 31, 2014.

Zydeco Revolving Credit Facility Agreement

On August 6, 2014, Zydeco entered into the Zydeco Revolver, a senior unsecured revolving credit facility agreement with STCW.  The facility has a borrowing capacity of $30.0 million. Loans advanced under the agreement have up to a six-month term. Borrowings under the credit facility bear interest at the three-month LIBOR rate plus a margin. As of December 31, 2015 the interest rate for the Zydeco Revolver was 1.8%. The credit agreement governing the Zydeco Revolver provides for covenants such as requiring pari passu ranking with any new indebtedness and contains customary events of default, such as nonpayment of principal when due, nonpayment of interest, fees or other amounts, violation of covenants, and cross-payment default (due to indebtedness in excess of $100 million). The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees and matures in August 2019.

During 2014, Zydeco had borrowings of $6.0 million from its revolving credit facility agreement in order to meet working capital requirements, which were repaid within two months of the withdrawal. Interest and fees incurred was approximately $0.1 million.  There were no outstanding borrowings on the Zydeco Revolver as of December 31, 2015 and 2014.

As of December 31, 2015, we were in compliance with the covenants contained in the Five-Year Revolver and the 364-Day Revolver, and Zydeco was in compliance with the covenants contained in the Zydeco Revolver.

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.

Pecten Line of Credit

On October 29, 2015, Pecten borrowed $6.0 million under a temporary line of credit with STCW.  Pecten repaid this loan on November 25, 2015 and canceled this line of credit shortly thereafter.

 

 

10. Leases

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 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-

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service date, which is expected to occur during the second quarter of 2016, our monthly lease payment will be $0.4 million. In the eighteenth month after the in-service date, actual fixed and variable costs will be compared to premised costs. If the actual and premised operating costs differ by more than 5.0%, the lease will be adjusted accordingly and this adjustment will be effective for the remainder of the lease. The imputed interest rate on the capital portion of the lease is 15.7%.

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 was $0.6 million for each of 2015, 2014 and 2013.

The future minimum lease payments as of December 31, 2015, for the above lease obligations were:

 

 

⁽¹⁾ Future minimum lease payments include $41.6 million in interest, $22.8 million in principal and excludes $11.3 million in executory costs.

As of December 31, 2015 and 2014, we had short-term payment obligations relating to capital expenditures totaling $1.9 million and $4.1 million, respectively. These represent unconditional payment obligations to vendors for products to be delivered in connection with capital projects.         

 

 

11. Equity

Private Placement

On the May 18, 2015, the Partnership completed the sale of the Common Units in the Private Placement for approximately $297.4 million net proceeds ($300.0 million gross proceeds, or $39.00 per Common Unit, less $2.6 million of placement agent fees). In connection with the issuance of the Common Units, the Partnership issued the general partner units to the general partner for $6.1 million in order to maintain its 2.0% general partner interest in the Partnership. The Partnership used the net proceeds of the Private Placement to partially fund the May 2015 Acquisition. See Note 3 — Acquisitions for additional details.

Registration Rights Agreement

In connection with the Private Placement, the Partnership entered into a Registration Rights Agreement with the investors, which granted them certain rights, including a requirement for us to file a shelf registration statement under the Securities Act with the SEC for the resale of the Common Units. On June 12, 2015, the Partnership filed a Registration Statement on Form S-1 with the SEC to register for resale the 7,692,308 Common Units issued and sold in the Private Placement. This registration statement was declared effective by the SEC on July 23, 2015.

On November 2, 2015, the Partnership filed a Registration Statement on Form S-3 with the SEC relating to an indeterminate number of common units and partnership securities representing limited partner interests.

Shelf Registration

On November 2, 2015, the Partnership filed a 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 interests.

On November 17, 2015, the Partnership completed the sale of 9,200,000 common units representing limited partner interests to unaffiliated third parties in the Offering for approximately $296.8 million net proceeds ($299.4 million gross proceeds, less $2.6 million of underwriters’ discount and other offering costs) and issued 187,755 general partner units to our general partner to maintain its 2.0% general partner interest.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Units Outstanding

As of December 31, 2015, we had 84,367,376 common units outstanding. SPLC owned 21,475,068 common units and 67,475,068 subordinated units, representing an aggregate 57.4% limited partner interest, all of the incentive distribution rights, and 3,098,825 general partner units, representing a 2.0% general partner interest in the Partnership.

The changes in the number of units outstanding from December 31, 2014 through December 31, 2015 are as follows:

 

 

Distributions to our Unitholders

The following table details the distributions declared and/or paid for the periods presented:

 

 

⁽¹⁾ The fourth quarter 2014 minimum quarterly distribution was prorated for the 59-day period from November 3, 2014 to December 31, 2014 in accordance with the Partnership Agreement.

⁽²⁾ For more information see Note 15 - Subsequent Events.

Distributions to Noncontrolling Interest

Distribution to noncontrolling interest in 2015 was $67.1 million. Distribution to noncontrolling interest in 2014 consists of (i) $25.2 million for the distribution paid to our Parent for its 57.0% equity interest in Zydeco and (ii) $6.8 million for the distribution payable to our Parent for the period October 1, 2014 through November 2, 2014.

 

12. Net Income Per Limited Partner Unit

Net income per unit applicable to common limited partner units and to subordinated limited partner units 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. 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 of our Predecessors related to acquired businesses for periods prior to their acquisition by us. Under the two class method these earnings must be allocated entirely to our General Partner. We have allocated these earnings of our Predecessors to our General Partner.  

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

The following tables show the allocation of net income to arrive at net income per limited partner unit:

 

 

 

 

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

13. Transactions with Major Customers and Concentration of Credit Risk

The following table shows revenues from third party customers that accounted for 10% or a greater share of consolidated revenues for the indicated years:

 

 

Our Parent and its affiliates accounted for 32%, 38% and 56% of our total revenues for 2015, 2014 and 2013, respectively. The following table shows accounts receivable from third party customers that accounted for 10% or a greater share of consolidated net accounts receivable for the indicated years:

 

 

We have a concentration of revenues and trade receivables due from customers in the same industry, our Parent’s affiliates, integrated oil companies, and independent exploration, production and refining companies. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory 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. We monitor the creditworthiness of our Parent, which has an investment grade credit rating and no history of collectability issues, and 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 transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2015 and 2014, 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, 2015, we had approximately $92.5 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.

As of December 31, 2015 and 2014, there were no accruals for environmental clean-up costs.

Legal Proceedings

SPLC and certain affiliates 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.

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 uncommitted (or non-contract) rates for uncommitted shippers effective December 1, 2015.  The

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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). We accrued $2.3 million for the settlement as of December 31, 2015 which was paid in January 2016. The Partnership has the right under the Omnibus Agreement to seek indemnification from SPLC for some of the costs incurred. 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.  

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.   For more information see Note 4 –Related Party Transactions.  

Other Commitments

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 an operating lease for land, and a capital lease for storage tanks.  For more information relating to our lease obligations, for more information see Note 4 –Related Party Transactions.

 

 

15. Subsequent Event(s)

We have evaluated events that occurred after December 31, 2015 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 February 11, 2016, we paid a cash distribution of $0.2200 per limited partner unit to unitholders of record on February 1, 2016, for the three months ended December 31, 2015. The total distribution paid was $35.3 million, with $13.8 million paid to our non-affiliated common unitholders and $19.6 million, $0.7 million and $1.2 million paid to SPLC for its common unit ownership, general partner interest and incentive distribution rights. See Note 11—Equity—Distributions to our Unitholders for more information.

Amendment and Restatement of Debt

On February 22, 2016, the Partnership and STCW again amended and restated the Five-Year Revolver to provide that loans advanced under the facility could have a term ending on or before its maturity date. This amendment and restatement makes it possible for the Partnership, at its option, to borrow under the facility for periods in excess of the one-year maximum time period previously stipulated in the agreement.

On February 22, 2016, the Partnership and STCW again amended and restated the 364-Day Revolver to extend its maturity to March 1, 2017.     All other terms and conditions of the agreement were unchanged.

Facilities Modification and Reimbursement Agreement

Zydeco and LOOP LLC, in which SPLC owns a 46.1% interest, entered into a Facilities Modification and Reimbursement Agreement effective January 15, 2016 wherein LOOP LLC agreed to undertake certain upgrades to its facilities to accommodate an additional 100 kbpd of crude receipts in Clovelly, Louisiana resulting from Zydeco electrical and pump upgrades at Houma, Louisiana.  If the upgrades are not complete by September 15, 2016, Zydeco agreed to reimburse LOOP LLC for the cost of the upgrades to its facilities up to $5.0 million, unless the project delay is due to force majeure or the parties mutually agreed to a later date.

 

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

16. Selected Quarterly Financial Data (Unaudited)

 

 

⁽¹⁾ Information has been retrospectively adjusted to include the Shell Auger and Lockport Operations for periods prior to October 1, 2015.

⁽²⁾ Information is not applicable for periods prior to the IPO .

The following table reconciles the previously reported amounts to those shown above.  This table shows 2015 and 2014 quarterly adjustments to total revenues, income before income taxes and net income applicable to our acquisition of the Shell Auger and Lockport Operations.

 

 

⁽¹⁾ Includes the consolidated results of the Partnership as previously reported in its 2015 quarterly reports.

⁽²⁾ Results of the Shell Auger and Lockport Operations from January 1, 2015 through September 30, 2015.

 

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⁽¹⁾ Includes the consolidated results of the Partnership as previously reported in its 2014 quarterly reports.

⁽²⁾ Results of the Shell Auger and Lockport Operations  for 2014.

 

 

 

 

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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, 2015.  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, 2015.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2015 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included in Part II, Item 8 of this report.

Remediation of Previously Identified Material Weaknesses

A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis.

As discussed in our Annual Report on Form 10-K for 2014 and subsequent Quarterly Reports on Form 10-Q, we did not maintain effective internal control over the completeness and accuracy of revenues. Specifically, controls were not designed or effectively operating to review the completeness and accuracy of journal entries required to properly accrue revenues and record loss/gain from pipeline operations. In addition, we did not maintain effective internal control over the accuracy of tariff rate allocations between Shell pipeline systems and associated inputs which impacts the accuracy and reporting of revenues. Specifically, effective controls were not designed or effectively operating to review the accuracy of tariff rate and associated inputs. Our management determined that these control deficiencies constituted material weaknesses.

As previously disclosed regarding the material weaknesses described above, we standardized processes, segregated financial data within the accounting system and implemented further controls to validate our financial data. Further, we engaged a third-party internal controls specialist firm to assist our management in a review of our existing control framework, the determination, development and implementation of new controls, the documentation of processes and the performance of control testing. Additional controls have been implemented to mitigate the associated risks and to support the completeness and accuracy of our financial reporting.  During 2015, we also designed, implemented and tested the following controls to address the material weakness:

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Based on the implementation of additional controls in previous quarters and the completion of our testing of their effectiveness in the fourth quarter, we have concluded the above referenced material weaknesses in internal control over financial reporting were remediated as of December 31, 2015.

Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting. However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

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 fourth quarter of 2015 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 or our general partner, Shell Midstream Partners GP LLC (the “General Partner”) and does not involve our or the General Partner’s management.

For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries other than us, the General Partner and Shell Midstream LP Holdings LLC as the “RDS Group”. 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, 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 2010, the RDS Group ceased all of its upstream commercial activities in Iran and suspended new business development in Iran, as a direct consequence of the international sanctions imposed on the country. In 2013, the RDS Group closed its small representative office in Iran.  

In 2015, the RDS Group paid $170,432 to the Iranian Ministry of Finance, consisting of a final settlement of corporate income tax related to the financial year ended December 31, 2013.

The RDS Group paid $6,113 to the Iranian Ministry of Finance, consisting of a final settlement of salary and withholding taxes related to the financial year ended December 31, 2013 and withholding taxes related to the first quarter of 2015.

The RDS Group paid $102 in stamp duties to the Iranian Ministry of Finance.

The RDS Group paid $7,866 to the Iranian Ministry of Finance for VAT claims related to the financial year ended December 31, 2009.

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These payments were made through the RDS Group’s Iranian accountant Bayat Rayan. The RDS Group paid $58,778 to its Iranian accountant Bayat Rayan for accounting and tax related services. These payments were made through cheques guaranteed by Bank Karafarin.

These transactions did not generate gross revenue or net profit. The RDS Group expects to make additional payments in support of the liquidation process of its legal entities in Iran. However, as a result of the suspension of U.S. and EU sanctions, the RDS Group is currently considering potential opportunities in Iran, which may lead it to suspend or stop the liquidation process in the future.

The RDS Group maintains accounts with Bank Karafarin where its cash deposits (balance of $3.0 million at December 31, 2015) generated non-taxable interest income of $0.5 million in 2015. The RDS Group paid $2 in bank charges to Bank Karafarin.

Payments to the Iranian Civil Aviation Authority for the clearance of overflight permits for RDS Group aircraft over Iranian airspace amounted to $10,278 in 2015. 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 its downstream business, through its subsidiary Deheza S.A.I.C.F.el., the RDS Group provided retail services in December 2015 to the Iranian Embassy in Argentina. This transaction generated a gross revenue of $42 and an estimated net profit of $8. The RDS Group has no contractual agreement with this embassy.

At December 31, 2015, the RDS Group has $1,971 million payable to, and $12 million receivable from, the National Iranian Oil Company (NIOC). The payable amount decreased by $193 million during 2015 as a result of currency movements. There was no change in the principal amount.

During 2015, RDS Group officials met Iranian officials in Tehran. They discussed the RDS Group’s outstanding debt to NIOC and potential areas for cooperation should sanctions be lifted. RDS Group officials also attended a conference in Iran for which a conference fee of $4,518 will be paid to IICIC (Iranian Inc for Contemporary International Conferences & Fairs).

In order to obtain visas for these officials, an amount of $699 was paid to the Iranian Embassy in the Netherlands, an amount of $408 was paid to the Iran Consulate in Dubai, United Arab Emirates and $59 was paid to the Iranian Consulate in Pakistan. There was no gross revenue or net profit associated with these transactions. The RDS Group expects to continue discussions with Iranian officials and therefore similar payments may continue in the future.

 

 

 

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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.

 

 

Curtis R. Frasier. Curtis Frasier became a member of the board of directors of our general partner and is the Chairman of the board of directors in connection with the IPO. 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 & 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.

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John H. Hollowell. John Hollowell was appointed Chief Executive Officer, President and member of the board of directors of our general partner in July 2015, and is also Executive Vice President of US Pipelines. He is a 35-year Shell executive with deep commercial and operations experience, as well as significant experience in Shell’s Supply and Distribution businesses. Most recently, John served as Executive Vice President of Deep Water for Shell in the Americas with responsibilities for Deep Water in the Gulf of Mexico, Brazil and Venezuela. Mr. Hollowell has also served as Vice President, Production for Exploration and Production in Europe from 2006-2009, where he was responsible for all Shell’s operated assets in the UK, Holland and Norway. Before that, from 2005-2006 Mr. Hollowell was Vice President, Distribution for Shell Downstream Inc., responsible for petroleum product terminal/depot operations and secondary distribution operations globally. Prior to that role, he worked in Shell’s downstream business in a series of roles, first joining in 1998 as the General Manager, Gulf of Mexico for Shell Pipeline Co. LP, then assuming the role of General Manager, Commercial in 2003, and being named Director of Shell Oil Products US, Distribution, and President of Shell Pipeline Company LP in January 2004. Prior to his work in Shell’s downstream business, he spent 1980-1998 in the group’s upstream business, during that period holding several assignments of increasing responsibility in engineering and operations. Mr. Hollowell holds a bachelor’s degree in Chemical Engineering from Texas A&M University. The Partnership believes that Mr. Hollowell’s 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.

Susan M. Ward. Susan Ward was appointed Vice President, Chief Financial Officer in May 2014, and became a member of the board of directors of our general partner in connection with the IPO. Ms. Ward has served as Head, M&A and Commercial Finance – Americas for Shell Oil Company since January 2010. Ms. Ward devotes the majority of her time to her role as Head, M&A and Commercial Finance and also spends time, as needed, devoted to our business and affairs. Since 2010, Ms. Ward has also served as Trustee and Vice Chairman of the Board of Trustees of the Shell Pension Trust and Chairman of its Investment Committee. Prior to her current role, Ms. Ward served as Vice President, Upstream Commercial Finance for Shell International Exploration & Production B.V. based in The Hague from 2007 to 2009. Since joining Shell in 1998, Ms. Ward has worked primarily in M&A and Commercial Finance roles across Shell’s global businesses. Since 2007, she has also served on the board of directors of Shell’s Bully deepwater drillship joint venture. Prior to joining Shell, Ms. Ward worked as an investment banker in the energy sector for 11 years at Kidder, Peabody, PaineWebber and UBS in New York and Houston, including as a Managing Director in the Natural Resources and Energy investment banking group of UBS Securities. Ms. Ward began her career working for Exxon Company USA as a refining engineer and also worked for Mobil Corporation in its Finance organization. Ms. Ward earned a Bachelor of Chemical Engineering degree from Villanova University and an MBA in Finance with distinction from the Wharton School of the University of Pennsylvania. We believe that Ms. Ward’s extensive experience in finance and M&A in the energy industry makes her well qualified to serve as a member of the board of directors of our general partner.

Michele F. Joy. Michele Joy became Vice President, Regulatory and Major Projects, of our general partner in connection with the IPO. Since April 2012, Ms. Joy has served as Vice President, SPLC and General Manager, Pipeline Growth. Ms. Joy devotes the majority of her time to her roles at SPLC and also spends time, as needed, devoted to our business and affairs. Ms. Joy joined SPLC in 2006 and is currently responsible for delivering major onshore and offshore pipeline projects. From 2008 to 2012, she was General Manager, Business Development for SPLC during a period of significant growth. She has also served as a Shell representative on a number of joint ventures, including Colonial, LOOP LLC, Poseidon Pipeline Company LLC and Explorer Pipeline Company. Ms. Joy is a member of the Department of Transportation’s Hazardous Liquid Pipeline Safety Advisory Committee and the Association of Oil Pipeline’s Economic Regulatory Committee. Prior to joining Shell, Ms. Joy served as the General Counsel for the Association of Oil Pipe Lines from 1991 to 2006. In that role, she was involved in the industry’s and regulators’ joint work to simplify economic regulation at the FERC; improve pipeline safety at the Department of Transportation (including pipeline integrity and the elimination of outside force damage); and support the EPA’s environmental improvements such as ultra-low sulfur diesel implementation. Ms. Joy also served five years as an adjunct professor at Northwestern University’s Transportation Institute and spent eight years in private practice focusing on gas and electric regulation and international law. Ms. Joy earned a Bachelor of Arts from Carleton College and a Juris Doctor from American University. She currently serves on the Board of Trustees of Carleton College.

Lori M. Muratta. Lori Muratta became Vice President, General Counsel and Secretary of our general partner in connection with the IPO. 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 role, 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.

Kevin M. Nichols. Kevin Nichols became Vice President, Commercial of our general partner in connection with the IPO. 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 also spends time, as needed, devoted to our business and affairs. Mr. Nichols is currently

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responsible for commercial activities that include business development, oil movements, tariffs, joint venture governance, and portfolio activity. Mr. Nichols currently sits on the joint venture board of Colonial as Shell’s representative and he also serves on the SPLC Leadership Team. Since joining Shell in 1991, Mr. Nichols has held numerous role 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.

Alton (Greg) G. Smith. Greg Smith became Vice President, Operations of our general partner in connection with the IPO. 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 Gulf of Mexico Business Development, Control Center Manager, and Manager of 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.

James (Jim) J. Bender. Jim Bender became a member of the board of directors of our general partner in connection with the IPO. 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 also 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. 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 Fierro became a member of the board of directors of our general partner on January 1, 2015. Mr. Fierro is a private investor based in Washington, D.C.  In addition to this board of directors, Mr. Fierro serves on the board of directors of Sendero Midstream Partners, a portfolio company of Energy Capital Partners, and on the board of directors and Audit Committee of Athabasca Oil Company, a Canadian energy company with a focused strategy on the development of thermal and light oil assets. 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.

Paul R. A. Goodfellow. Paul Goodfellow became a member of the board of directors of our general partner in connection with the IPO. Since February 2015, Dr. Goodfellow has served as Vice President, United Kingdom and Ireland for Shell U.K. Limited. From January 2013 to February 2015, Dr. Goodfellow served as the Vice President Unconventionals US and Canada for Shell Upstream Americas. 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 of 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

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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. Dr. Goodfellow serves on the board of the Center for Sustainable Shale Development. 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 in connection with the IPO. Mr. Jones is a private investor and consultant based in Houston, 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 is a member of the board of directors of our general partner. In June 2015, she retired as president and CEO of our general partner. 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 terminaling and distribution activities. In these various roles, Ms. Montana has led Shell’s U.S. pipeline business since 2006. In 2001, Ms. Montana became General Manager, Distribution for Shell’s Asia Pacific business based in Singapore and served on the Board of Shell Pakistan Limited. Ms. Montana began her more than 37-year career at Shell as an engineer in Shell’s Deer Park Refinery. Ms. Montana holds a bachelor of science in Chemical Engineering from the University of Missouri, Rolla. Ms. Montana currently serves as the Chair of the American Petroleum Institute Downstream Committee and is a member of the board of directors of the Houston YMCA. 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.

Gerard B. Paulides. Gerard Paulides became a member of the board of directors of our general partner in connection with the IPO.  Effective July 1, 2015, Mr. Paulides serves as Executive Vice President Deal Completion for RDS. From October 2012 through June 30, 2015, Mr. Paulides has served as Global Head of M&A and Commercial Finance for Shell covering acquisitions, divestments, joint ventures and structured financing for all of Shell’s worldwide businesses based at Shell’s headquarters in The Hague. From 2006 to 2012, Mr. Paulides served as Chief Financial Officer and Vice President, Strategy & Finance, for Shell’s upstream business in Europe while based in The Hague. During that time, Mr. Paulides also served as an Advisory Director of the Nederlandse Aardolie Maatschappij (NAM) 50/50 joint venture between Shell and Exxon controlling major oil and gas assets in the Netherlands, Norway, UK, Ireland, Denmark, Germany and Italy. Mr. Paulides served as Chief Financial Officer and Senior Executive Director of Shell Canada in 2007, and was responsible for the integration of the acquisition of the outstanding public minority shares of Shell Canada by Royal Dutch Shell at that time. From 2003 to 2007, Mr. Paulides served in Shell Investor Relations in London, UK, during which period Shell Transport and Trading and Royal Dutch were unified into Royal Dutch Shell. From 2000 to 2003, he served as Deputy Chief Financial Officer for Shell Gas & Power in London in a role that included responsibility for project finance and M&A in that business. Previous roles at Shell included Controller, Shell Netherlands Chemicals and positions in Shell Crude Oil Trading in London, Shell Marketing Oil Products in Uganda, and Shell Exploration & Production in the Netherlands. Mr. Paulides earned a Masters degree in Business Economics from the University of Brabant in the Netherlands. We believe that Mr. Paulides’ extensive experience in financial and mergers and acquisitions roles in the energy industry makes him well 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

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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 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, 2015 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

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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.

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 percent 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 2015, all Section 16(a) reports applicable to our officers and directors were filed on a timely basis, except that the following reports were filed late: one Form 3 for James Fullen upon becoming an officer of the Partnership, four Forms 4 relating to four open market purchases upon distribution reinvestments by Michele Joy, and one Form 4 relating to one open market purchase upon a distribution reinvestment by Margaret Montana.

Item 11. EXECUTIVE COMPENSATION

We and our general partner were formed in March 2014 and did not accrue any obligation with respect to compensation for directors and officers for the 2013 fiscal year or for any prior periods.  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:

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 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, principal financial officer and the most highly compensated executive officer other than its principal executive officer and principal financial officer as of December 31, 2015, being:

·Margaret C, Montana, President and Chief Executive Officer ⁽¹⁾

·John H. Hollowell, President and Chief Executive Officer ⁽²⁾

·Susan M. Ward, Vice President and Chief Financial Officer

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·Michele F. Joy, Vice President, Regulatory and Major Projects 

·Lori M. Muratta, Vice President, General Counsel and Secretary

·Kevin M. Nichols, Vice President, Commercial

·Greg G. Smith, Vice President, Operations

⁽¹⁾  Ms. Montana served as our Chief Executive Officer from May 1, 2014 through June 30, 2015.

⁽²⁾  Mr. Hollowell became our Chief Executive Officer effective July 1, 2015.

Each of Mr. Hollowell, Ms. Ward, Ms. Joy, Ms. Muratta, Mr. Nichols, and Mr. Smith devote a significant portion of their time to their roles in Shell and spend time, as needed, directly managing our business and affairs. Margaret C. Montana served as President and Chief Executive Officer of our general partner from May 1, 2014 through June 30, 2015. 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. Hollowell, Ms. Ward, Ms. Joy, Ms. Muratta, Mr. Nichols, or Mr. Smith 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.  During her tenure as President and Chief Executive Officer of our general partner, Ms. Montana did not receive any separate amounts of compensation for her services to our business or as an executive officer 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 her.  However, from July 1, 2015 to December 31, 2015, Ms. Montana was compensated for her services as a director on our general partner’s board of directors as described in the table below.

Summary Compensation Table

The following summarizes the total compensation paid to our NEOs for their services in relation to our business since our inception as a separate company in March 2014.

 

 

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

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Shell, Mr. Hollowell and Ms. Ward have end of employment arrangements with Shell under which they would receive 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.

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.

Severance Arrangements

Mr. Hollowell and Ms. Ward are participants in Shell’s Senior Executive end of employment arrangements. Eligibility to receive certain separation payments and benefits under this arrangement is based on termination of employment at the employer’s initiative or on mutually agreed terms. The agreements provide generally that the named executive officers upon their separation from Shell would receive a payment or payments up to their annual base salary plus the on target annual bonus for their job grade. In addition, any outstanding conditional awards made under Shell’s Performance Share Plan and Long Term Incentive Plan may continue to vest in accordance with the terms and conditions of the applicable grant, depending on the terms of the separation from service. If an officer’s employment is terminated for “cause” the officer will not receive any benefits or compensation under the plan other than accrued salary or vacation pay that remained unpaid through the date of termination. Participants in Shell’s Senior Executive end of employment arrangements are not eligible to participate in any other Shell severance program.

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 such directors $150,000. We currently pay the audit committee chairman an additional $15,000 and the conflicts committee chairman an additional $15,000. 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 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.

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Non-Employee Director Compensation Table

The following summarizes the compensation for our non-employee directors for 2015.

 

 

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.

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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

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

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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 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

Carlos A. Fierro

Paul R. A. Goodfellow

John H. Hollowell ⁽¹⁾

Rob L. Jones

Margaret C. Montana ⁽²⁾

Gerard B. Paulides

Susan M. Ward

⁽¹⁾ Mr. Hollowell became our Chief Executive Officer effective July 1, 2015.

⁽²⁾  Ms. Montana served as our Chief Executive Officer from May 1, 2014 through June 30, 2015.

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Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan ⁽¹⁾

The following table sets forth information about Shell Midstream Partners, L.P. common units that may be issued under all existing equity compensation plans as of December 31, 2015.

 

 

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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 84,367,376 common units and 67,475,068 subordinated units being outstanding.

 

 

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Item 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS, AND DIRECTOR INDEPENDENCE

As of February 26, 2016 the general partner and its affiliates owned 21,475,068 common units and 67,475,068 subordinated units, representing a 57.4% limited partner interest in us, and all of our incentive distribution rights. In addition, our general partner owned 3,098,825 general partner units representing a 2.0% 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.

Operational Stage

 

 

Omnibus Agreement

In connection with the IPO we entered into an Omnibus Agreement with SPLC and our general partner that addressed the following matters:

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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 of Administrative Fee and Reimbursement of Expenses. We pay SPLC an administrative fee, initially $8.5 million (payable in equal monthly installments and prorated for the first year of service), for the provision of certain general and administrative services for our benefit, including services related to the following areas: executive services; financial and administrative services (such as treasury and accounting); information technology services; legal services; corporate health, safety and environmental services; human resources services; procurement services; corporate engineering services; business development services; investor relations and public affairs and tax matters.

Under this agreement, we also reimburse SPLC for all other direct or allocated costs and expenses incurred by SPLC in providing these services to us. This reimbursement is in addition to our reimbursement of our general partner and its affiliates for certain costs and expenses incurred on our behalf for managing and controlling our business and operations as required by our partnership agreement.

Our general partner also pays to SPLC on behalf of us all expenses incurred by SPLC as a result of us becoming and continuing as a publicly traded entity. We reimburse our general partner for these expenses to the extent the fees relating to such services are not included in the general and administrative services fee.

Our general partner, in good faith, may adjust the administrative fee to reflect the contribution, acquisition or disposition of our assets, a change in the scope of services provided to us, inflation or a change in law or other regulatory requirements.

At the end of each calendar year, we have the right to submit to SPLC a proposal to reduce the amount of the administrative fee for that year if we believe that the general and administrative services performed by SPLC for our benefit for the year in question do not justify payment of the full administrative fee for that year.

Environmental Indemnification by SPLC. Under the Omnibus Agreement, SPLC will indemnify us for all violations of environmental laws and all environmental remediation or corrective action that is required by environmental laws, in each case to the extent (i) related to the ownership or operatorship assets contributed to us by SPLC and (ii) not identified in a voluntary audit or investigation undertaken outside the ordinary course of business by us. SPLC will also indemnify us for certain known and scheduled environmental matters related to our assets (“Scheduled Environmental Matters”). Except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us for any environmental losses unless SPLC is notified of such losses prior to the third anniversary of the closing of the IPO. Furthermore, except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us until our aggregate indemnifiable losses in any year exceed a $0.5 million deductible (and then SPLC will only be obligated to indemnify us for amounts in excess of such deductible). SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15.0 million.

Other Indemnifications by SPLC. SPLC will also indemnify us for the following, to the extent not covered by the above-described environmental indemnity:

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SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15.0 million. SPLC’s indemnity obligation for tax liabilities and liabilities associated with SPLC’s retained assets is not subject to a cap.

Indemnification by Us. We have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets (other than any environmental liabilities for which SPLC is specifically required to indemnify us as described above). There is no limit on the amount for which we will indemnify SPLC under the Omnibus Agreement.

License of Trademarks. Shell granted us a nontransferable, nonexclusive, royalty-free worldwide right and license to use certain trademarks and trade names owned by Shell.

Termination. The Omnibus Agreement, except for the indemnification provisions, will terminate by written agreement of all the parties thereto or by SPLC or us immediately at such time as SPLC ceases to control our general partner.

Contracts with Affiliates, Joint Venture and Subsidiary Governing Documents

Zydeco Limited Liability Company Agreement

General. SPLC contributed and Zydeco issued to us interests in Zydeco collectively representing an aggregate 62.5% ownership interest in Zydeco. SPLC owns the remaining 37.5% membership interest in Zydeco. Pursuant to a voting agreement that we executed with SPLC, we control cash distributions by Zydeco.

We and SPLC are parties to the limited liability company agreement of Zydeco, a Delaware limited liability company. The limited liability company agreement of Zydeco governs the ownership and management of Zydeco. The agreement may not be amended without the unanimous consent of the members. The purpose of Zydeco under the limited liability company agreement is generally to own and operate Zydeco pipeline, market the services of the pipeline and engage in any other related activities.

Governance. Zydeco is manager managed, and we are the sole manager.

Quarterly Cash Distributions. The Zydeco limited liability company agreement provides for quarterly cash distributions to the members equal to Zydeco’s “distributable cash,” which is defined to include the cash and cash equivalents of Zydeco less the amount of any cash reserves established by the manager.

Capital Calls. From time to time the members, by unanimous written consent, may approve a capital contribution, with each member contributing to Zydeco its pro rata share of the capital contribution.

Transfer Restrictions. Under the voting agreement between us and SPLC, SPLC will agree not to transfer any portion of its ownership interest in Zydeco unless, among other conditions, after giving effect to the proposed transfer, (i) we would be able to consolidate the financial results of Zydeco in our consolidated financial statements, (ii) we would control cash distributions by Zydeco, and (iii) we would be deemed to control Zydeco for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Zydeco.

Termination. Zydeco will dissolve only upon the occurrence of any of the following events:

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Mars Partnership Agreement

General. SPLC contributed to us 40.0% of its 71.5% ownership interest in Mars, as a result of which we own a 28.6% interest in Mars, SPLC own a 42.9% interest and an affiliate of BP owns the remaining 28.5% interest. Pursuant to a voting agreement with SPLC, we have voting power sufficient such that any cash reserves by Mars that reduce the amount of distributable cash require our approval; however, the amount of reserves will also be influenced by the capital budget, which must be approved by us and the other partner.

We, SPLC and an affiliate of BP are parties to the partnership agreement of Mars, a Texas general partnership. The partnership agreement of Mars governs the ownership and management of Mars. The purpose of Mars under the partnership agreement is generally to own and operate the crude oil pipeline system and related facilities owned by the partnership and to conduct such other business activities as the partnership committee determines is necessary or appropriate in such ownership and operation.

Under the partnership agreement each partner and its affiliates may engage in other business opportunities, including those that compete with Mars’ business, free from any obligation to disclose the same to the other partner or the partnership.

Governance. Mars is managed by a partnership committee composed of one representative designated by each partner; provided that we and SPLC will collectively be deemed one partner for this purpose and will appoint only one representative. All acts of management of the partnership are taken by the partnership committee, by agents duly authorized in writing by the partnership committee or by SPLC, the operator under the Mars operating agreement, which we refer to as the Mars operator. The partnership committee has full power and authority to manage the entire business and affairs of the Mars System and oversee the operations of the Mars operator.

The partnership committee is required to meet no less often than annually, with the time and location of such meetings to be as the partnership committee determines. Special meetings of the partnership committee may be called by the chairman of the partnership committee or by the chairman or secretary of the partnership committee upon request of the partnership committee. The presence in person, or by conference telephone call, of members of the partnership committee representing at least two partners and 51.0% of the ownership interests constitutes a quorum of the partnership committee.

Except as noted below, all decisions of the partnership committee require the vote of at least 51.0% of the ownership interests in the partnership. Through our voting agreement with SPLC, we will be able to vote a majority of the ownership interests.

The following actions require the vote of members representing 100.0% of the ownership interests:

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If the partnership is composed of only two partners, the following actions require the vote of members representing 100.0% of the ownership interests; if the partnership is composed of more than two partners, these actions only require the vote of a majority of the ownership interests. We entered into an amendment to the Mars partnership agreement that provides that, for purposes of the voting provisions under the Mars partnership agreement, we and SPLC together constitute one partner. As a result, the following actions require the approval of the unaffiliated third party:

If the partnership is composed of only two partners, the following actions require the vote of members representing 28.5% of the ownership interests; if the partnership is composed of more than two partners, these actions require the vote of a majority of the ownership interests. As described above, we and SPLC are deemed one partner and the following actions will require the approval of the unaffiliated third party:

In lieu of a meeting, the partnership committee may elect to act by unanimous written consent of all members of the partnership committee.

Cash Distributions. The Mars partnership agreement provides for cash distributions to the partners from time to time equal to Mars’ “distributable cash,” which is defined to include the gross cash proceeds from operations less the portion thereof used to pay or establish reserves as determined by the partnership committee. The Mars operator is required to review the partnership accounts, not less often than quarterly, to determine the amount of distributable cash available and recommend to the partnership committee the amount to be distributed. Upon approval of the partnership committee by a vote of the majority of the ownership interests, the Mars operator shall promptly distribute the distributable cash to the partners in accordance with their ownership interests.

Capital Calls to the Partners. From time to time as determined by the partnership committee by a vote of the majority of the ownership interests, the partnership committee may issue a capital call notice to the partners of the partnership for capital contributions to be made to fulfill the purposes for which the partnership is created. The partnership committee will specify the amount of the capital contribution from each partner individually, which amount shall be in proportion to the ownership interest of that partner in Mars.

Transfer Restrictions. Under the Mars partnership agreement, each partner’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other partners. The right of first refusal does not apply in the case of transfers to an affiliate if such affiliate, or a company which wholly owns such affiliate, (i) satisfies certain financial responsibility requirements set forth in the partnership agreement and (ii) expressly assumes the obligations of the partnership agreement. In addition, if a partner proposes to dispose of an interest in a transferee affiliate, then the other partners must provide consent or the transferee affiliate must satisfy certain criteria. Under the voting agreement between SPLC and us, SPLC agrees not to transfer any portion of its ownership interest in Mars unless, among other conditions, after giving effect to the proposed transfer, (i) we would continue to control the amount of cash distributions by Mars and (ii) we would be deemed to control Mars for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Zydeco.

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Termination. The Mars partnership agreement provides that Mars will terminate, unless extended or terminated by the partners, on December 31, 2026. Mars will dissolve only upon the occurrence of any of the following events:

Bengal Limited Liability Company Agreement

General. SPLC contributed to us 98.0% of its 50.0% ownership interest in Bengal, as a result of which we own a 49.0% interest in Bengal, SPLC owns a 1.0% interest and Colonial owns the remaining 50.0% interest. Pursuant to an agreement with SPLC, we have voting power sufficient such that any cash reserves by Bengal that reduce the amount of cash distributed by Bengal require our approval.

We, SPLC and Colonial are parties to the limited liability company agreement of Bengal, a Delaware limited liability company. The limited liability company agreement of Bengal governs the ownership and management of Bengal. The purpose of Bengal under the limited liability company agreement is generally to own and operate the pipeline system, market the services of the pipeline system and engage in any other related activities.

Governance. Management of Bengal is vested in a two person board of managers, with Colonial appointing one manager and SPLC and us jointly appointing the other manager. No manager or member is authorized to act on behalf of Bengal, perform an act that would be binding on Bengal or incur any obligation or make any expenditure on behalf of Bengal, except as provided for in the limited liability company agreement of Bengal or in a binding written agreement between a member and Bengal.

The board of managers is required to meet no less often than semi-annually but may meet with a greater frequency as the managers may approve. The location of such meetings is Bengal’s principal office or such other place as shall be specified, along with the agenda, in the written notice of such meetings. Special meetings of the board may be called at such times as any manager determines to be necessary. The presence in person, by telephone or by proxy of all of the managers constitutes a quorum for the transaction of business at any board meeting. Each manager is entitled to cast votes equal to the product of one hundred and the current ownership interest of such manager’s appointing member on each matter voted upon by the board.

The affirmative vote of 80.0% of the voting power of all managers eligible to vote on the matter is required to adopt a matter. A manager is not eligible to vote on a matter due to a conflict of interest when (i) the matter concerns the level of tariffs or other charges of Bengal to be paid by shippers on the pipeline system or Bengal’s tariff policies and (ii) the manager’s appointing member or such member’s affiliate owns an ownership interest in any shipper on the pipeline system greater than its ownership interest in Bengal. Any action of the board may be taken by written consent of all of the managers entitled to vote on the action.

The following actions require the unanimous approval of the members before authorization by the board of managers:

The members are required to meet with such frequency as the members may approve. The location of such meetings is Bengal’s principal office or such other place as shall be specified, along with the agenda, in the written notice of such meetings. Special meetings of the members may be called at such times as any member determines to be necessary. The presence in person, by telephone or by proxy of all of the members constitutes a quorum for the transaction of business at any meeting of the members. Each

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member is entitled to cast votes equal to the product of one hundred and the member’s current ownership interest on each matter voted upon by the board. Except as noted above, the affirmative vote of 80.0% of the voting power of all members is required to adopt a matter. Any action of the members may be taken by written consent of all of the members entitled to vote on the action.

Quarterly Cash Distributions. Bengal is required by the terms of its limited liability company agreement to make quarterly cash distributions to the members equal to 100.0% of Bengal’s “available cash,” which is defined to include the unrestricted cash and cash equivalents of Bengal less reasonable cash reserves, including those necessary for working capital and obligations or other contingencies of Bengal, as the board determines is proper to set aside in the best interests of Bengal. The board managers appointed by Colonial and us must jointly make the determinations related to Bengal’s establishment of cash reserves. Distributions are required to be made simultaneously to all members in proportion to their ownership interests within 30 days following the end of each quarter.

Capital Calls to the Members. From time to time, upon the unanimous approval of the members, the board of managers may issue a capital call notice to the members for capital contributions to be made, with such capital contributions including but not limited to contributions of cash, promissory notes or property. The notice will specify the amount of the capital contribution from all members collectively, the form and amount of the capital contribution from the member to whom such notice is addressed, the purpose for which the funds will be used, the date that the contributions are to be made and the method of contribution.

Transfer Restrictions. Under the Bengal limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. The right of first refusal does not apply in the case of transfers to an affiliate if the membership interest being transferred constitutes no more than 50.0% of the fair market value of such affiliate’s assets. In addition, if a member proposes to dispose of an interest, then the other members must provide consent and the board of managers must approve certain documents related to such transfer. Under the voting agreement between SPLC and us, SPLC will agree not to transfer any portion of its ownership interest in Bengal unless, among other conditions, after giving effect to the proposed transfer, (i) we would continue to have sufficient voting power such that any cash reserves by Bengal that would reduce the amount of cash distributed require our approval and (ii) we would be deemed to control Bengal for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Bengal.

Termination. The Bengal limited liability company agreement provides that Bengal will terminate when a certificate of cancellation is filed in the office of the Secretary of State of the State of Delaware. Bengal will be dissolved upon the occurrence of either (i) the unanimous vote of the members to dissolve the company or (ii) any other event causing a dissolution of the company under the Delaware Act.

Poseidon Limited Liability Company Agreement

General. SOPUS contributed to us its 36.0% ownership interest in Poseidon. The remaining interests in Poseidon are owned by a third-party operator.

We and the third-party operator are party to the limited liability company agreement of Poseidon, a Delaware limited liability company. The limited liability company agreement, as amended through the fifth amendment thereto, of Poseidon governs the ownership and management of Poseidon. The purpose of Poseidon under the limited liability company agreement is generally to own and operate the pipeline system and engage in any other related activities.

Governance. Poseidon is managed by a management committee composed of one representative from each member. All acts of management are taken by the members, the management committee or by such other committee as authorized by the members, including the business development committee, and the operating committee.  The management committee is responsible for the planning and oversight of the policies and strategies of the company, the business development committee is responsible for the planning and oversight of specific business development projects, and the operating committee is responsible for the oversight and control of the physical operations and maintenance of the pipeline system. No member is individually authorized to bind Poseidon, except as expressly provided for in the limited liability company agreement of Poseidon or by an act of the members, a duly authorized committee or other representative of Poseidon.

The members are required to meet no less often than annually, with the time and location of such meetings to be determined by the members. The business development and operating committees are required to meet at least annually. Special meetings of the members or the committees may be called at such times as requested (i) by the president or secretary of Poseidon, (ii) by a representative of a member at the written request of the president, (iii) by members holding at least 20.0% of the ownership interests in Poseidon or (iv) by at least two members. The presence in person, or by conference telephone call, of the members or the members of the respective committee representing at least 28.0% of the ownership interests constitutes a quorum. Each member representative is entitled to cast one vote per percent of ownership interests of such representative’s appointing member on each matter voted upon by the respective committee. Any action of the members or a committee may be taken by written consent of all of the members or member representatives, as applicable, entitled to vote on the action.

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The following actions require the approval of the members holding at least 72.0% of the ownership interests in Poseidon:

Quarterly Cash Distributions. Poseidon is required by the terms of its limited liability company agreement to make monthly cash distributions to the members equal to 100.0% of Poseidon’s “available cash,” which is defined to include the unrestricted cash and cash equivalents of Poseidon less reasonable cash reserves, including those necessary for working capital and obligations or other contingencies of Poseidon, as the members or management committee determines is proper to set aside in the best interests of Poseidon. The member representatives must collectively make the determinations related to Poseidon’s establishment of cash reserves. Distributions are required to be made simultaneously to all members in proportion to their ownership interests within 30 days following the end of each calendar month.

Capital Calls to the Members. From time to time the members, by unanimous written consent, may approve a capital contribution, with each member contributing to Poseidon its pro rata share of the capital contribution. Any member may propose in writing to the other members that the members make a capital contribution if such member makes a determination in good faith that it is in the best interest of Poseidon.

Transfer Restrictions. Under the Poseidon limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. The right of first refusal does not apply in the case of transfers to an affiliate if such affiliate (i) satisfies certain net worth tests set forth in the limited liability company agreement and (ii) expressly assumes the obligations of the limited liability company agreement. If a member proposes to dispose of an interest, then the other members must provide consent. Consent is not required in the case of transfers to an affiliate if such affiliate satisfies certain net worth tests set forth in the limited liability company agreement.

Termination. Poseidon will be dissolved upon the occurrence of any of the following events:

Pecten Midstream LLC Limited Liability Company Agreement

General. SPLC contributed and Pecten issued to us 100.0% of the interest in Pecten.

Shell Midstream Operating LLC is the sole member of Pecten, a Delaware limited liability company. The limited liability company agreement of Pecten governs the ownership and management of Pecten. The agreement may not be amended without the unanimous consent of the members. The purpose of Pecten under the limited liability company agreement is generally to own and operate Auger Pipeline System, market the services of the Auger Pipeline System, maintain and operate the Lockport Terminal and engage in any other related activities.

Governance. Pecten is member managed.

Quarterly Cash Distributions. The Pecten limited liability company agreement provides for quarterly cash distributions to the members equal to Pecten’s “distributable cash,” which is defined to include the cash and cash equivalents of Pecten less the amount of any cash reserves established by the members.

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Capital Calls. From time to time the members, by unanimous written consent, may approve an additional capital contribution.

Transfer of ownership interests. Members may assign their ownership interests in Pecten in whole or in part, subject to the terms of the Pecten limited liability company agreement.  

Termination. Pecten will dissolve upon the earliest to occur of the following events:

Pecten Midstream LLC Operating Agreement

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.

Colonial Organizational Documents

General. SPLC contributed to us 18.6% of its 16.12% ownership interest in Colonial, as a result of which we own a 3.0% interest in Colonial and SPLC owns a 13.12% interest in Colonial. The remaining interests in Colonial are owned by third parties.

We, SPLC and certain other third parties are parties to the shareholder agreement of Colonial, a Delaware and Virginia corporation. The shareholder agreement, articles of incorporation and bylaws of Colonial govern the ownership and management of Colonial. The purpose of Colonial under its articles of incorporation is generally to build, acquire and operate pipelines and related facilities for the transportation of crude oil and refined products.

Governance. Colonial is managed by a five-person board of directors. Each shareholder is required to vote its shares such that at all times one person, but not more than one person, nominated by each shareholder will be a member of the board of directors, provided that no such shareholder is required to vote its shares in favor of the nominee of a shareholder which either (i) has disposed of 80.0% or more of the shares which it held as of the date upon which it became a party to the shareholder agreement or (ii) owns less than 2.5% of the total outstanding stock of Colonial at the time of such vote.

Under the bylaws of Colonial, the board of directors is required to meet from time to time, with the time and location of such meetings as shall be fixed at a previous board meeting and published in such previous board meeting’s minutes. Special meetings of the board may be called by the chairman of the board, or by the chairman of the board or secretary on the written request of two directors. The presence of a majority of the board constitutes a quorum for the transaction of business at any board meeting. Except as noted below, all acts of the board require the vote of a majority of the directors present at any meeting at which there is a quorum.

The following actions require the vote of 75.0% of the board:

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Certain actions also require approval by shareholders. The vote of a majority of the stock issued, outstanding and entitled to vote is required to amend Colonial’s articles of incorporation. The following actions require the vote of 75.0% of the stock issued, outstanding and entitled to vote:

Amendments of certain sections of Colonial’s articles of incorporation require the vote of 80.0% of the stock issued, outstanding and entitled to vote, while amendments of other sections require the vote of 100.0% of the stock issued, outstanding and entitled to vote. Other than the actions which require unanimous approval by the shareholders, SPLC and the other shareholders of Colonial will be able to collectively make all decisions with respect to the operation of Colonial without our approval.

Cash Distributions. Colonial has historically made dividends to its shareholders in an amount approximately equal to each shareholder’s pro rata share of Colonial’s net income.

Subscription Rights. Under Colonial’s restated articles and certificate of incorporation, the shareholders of Colonial have the right to subscribe for the shares of any authorized but unissued stock that is to be issued, the shares of any new class of stock that is to be created, the additional shares of any class that is to be increased and the right to buy any bonds, notes, debentures or other securities, convertible into stock, before the same is offered for subscription or sale or is otherwise issued, in proportion to the number of shares owned by each of the holders of such stock exercising these rights.

Transfer Restrictions. Under the Colonial shareholder agreement, each shareholder’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other shareholders. The right of first refusal does not apply in the case of a merger or consolidation to which a shareholder is a party, a sale of all or substantially all of the assets of a shareholder, a transfer of the selling shareholder’s assets to its stockholders as a liquidation dividend in connection with its dissolution or a transfer to an affiliate, so long as the corporation surviving the merger or consolidation, the person purchasing the shareholder’s assets, the person receiving the liquidating dividend or the affiliate receiving the stock expressly assumes the obligations of the Colonial shareholder agreement.

Voting Agreements

Pursuant to voting agreements between SPLC and us, we have voting power over the ownership interests retained by SPLC in Zydeco, Mars and Bengal. Pursuant to the voting agreements, SPLC is prohibited from transferring its ownership interest in these entities unless the transferee agrees to be bound by the applicable voting agreement.

Revolving Credit Facility

On October 31, 2014, in connection with the IPO, we entered into a $300.0 million credit facility, the Five-Year Revolver. On May 12, the Partnership and STCW amended and restated the Five-Year Revolver to increase the borrowing capacity amount to $400.0 million. The credit facility matures on the fifth anniversary of the closing date of the agreement. Borrowings under the credit facility are generally available for working capital purposes. Our obligations under the credit facility rank at least pari passu with the claims of all our other unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally. Borrowings under the credit facility bear interest, which is calculated based on the three months LIBOR as of the quotation day relating to the interest period. This facility also includes customary fees, including an issuance fee, commitment fees, utilization fees and other fees. The credit agreement contains events of default customary for credit facilities of this nature, including, but not limited to, the failure to pay any principal, interest or fees when due, failure to satisfy any covenant, untrue representations or warranties, events of default under any other loan document under the new credit facility, default under any other material debt agreements, our insolvency, involvement in certain insolvency proceedings, initiation of certain creditors’ processes, unlawfulness and invalidity of the credit agreement and our repudiation of the agreement. Upon the occurrence and during the continuation of an event of default under the credit agreement, the lenders may, among other things, accelerate and declare the outstanding loans to be immediately due and payable and exercise remedies against us as may be available to the lenders under the credit agreement and other loan documents. On February 22, 2016, the Partnership and STCW again amended and restated the Five-Year Revolver to provide that loans advanced under the facility would have maturity dates, selected by the Partnership, up to October 31, 2019, the maturity date of the Five-Year Revolver.

On June 29, 2015, we entered into a $100.0 million credit facility, the 364-Day Revolver. On November 11, 2015, the Partnership and STCW amended and restated the 364-Day Revolver to increase the borrowing capacity amount to $180.0 million. On February 22, 2016, the Partnership and STCW again amended and restated the 364-Day Revolver to extend its maturity date to March 1, 2017. The amendments enable roll-over of outstanding amounts as they come due, up to facility maturity date.

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Zydeco has entered into a revolving credit facility with an affiliate of Shell as the lender. The facility has a borrowing capacity of $30.0 million and we expect this new credit facility. Indebtedness under the revolving credit facility bears interest at LIBOR plus a margin, which is based on a derived credit rating and market conditions. The credit agreement governing the revolving credit facility provides for customary covenants for comparable commercial borrowers and contains customary events of default, such as nonpayment of principal when due; nonpayment of interest, fees or other amounts; violation of covenants; cross-payment default (to indebtedness in excess of a threshold amount). The revolving credit facility also requires payment of customary fees, including issuance and commitment fees. The revolving credit facility matures in August 2019.

Tax Sharing Agreement

Zydeco has entered into a tax sharing agreement with an affiliate of Shell pursuant to which Zydeco has agreed to reimburse Shell for state and local income and franchise taxes attributable to Zydeco’s activity that is reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under the agreement equal the amount of tax that Zydeco would be required to pay if it were to file a consolidated, combined or unitary tax return separate from Shell. Shell will compute and invoice Zydeco for the reimbursement amount within 90 days of Shell filing the combined or unitary tax return on which Zydeco’s activity is included. Zydeco may be required to make prepayments toward the reimbursement amount to the extent that Shell is required to make estimated tax payments. No payments were made in 2015.

Other Agreements

SPLC is party to a pipeline operating agreement with Mars. Under the terms of the pipeline operating agreement, SPLC, on behalf of Mars, pays for the operation, maintenance, upkeep and repair of the pipeline facilities and Mars reimburses SPLC for all costs and expenses incurred in connection with providing services under the agreement. The agreement renews automatically from year to year unless either SPLC or Mars terminates the agreement prior to the end of the calendar year. Mars incurred $7.5 million in 2015 for services rendered under this agreement.

SPLC is party to a pipeline operating agreement with Bengal. Under the terms of the pipeline operating agreement, Bengal pays for operating and support services for the operation, maintenance, and repair of the pipeline facilities. Bengal also reimburses SPLC for certain direct expenses incurred in connection with providing services under the agreement. The agreement was renewed in 2012 for a three-year period and expires on December 31, 2015. Bengal incurred $12.5 million in 2015 for services rendered under this agreement.

Zydeco and LOOP LLC, in which SPLC owns a 46.1% interest, entered into a Facilities Modification and Reimbursement Agreement effective January 15, 2016 wherein LOOP LLC agreed to undertake certain upgrades to its facilities to accommodate an additional 100 kbpd of crude receipts in Clovelly, Louisiana resulting from Zydeco electrical and pump upgrades at Houma, Louisiana.  If the upgrades are not complete by September 15, 2016, Zydeco agreed to reimburse LOOP LLC for the cost of the upgrades to its facilities up to $5.0 million, unless the project delay is due to force majeure or the parties mutually agreed to a later date.

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.

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Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

The following table presents fees for 2015 and 2014 for professional services performed by our independent registered public accounting firm, PricewaterhouseCoopers LLP (PwC).

 

 

⁽¹⁾ Fees for audit services related to the fiscal year consolidated audit, quarterly reviews, the IPO, registration statements, and services that were provided in connection with statutory and regulatory filings.

⁽²⁾ Total audit-related fees incurred in 2014 prior to the IPO were $2.8 million and were paid by SPLC.

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 PwC 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 PwC’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 PwC must be pre-approved by the Audit Committee. 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.

 

 

 

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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

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.

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SHELL MIDSTREAM PARTNERS, L.P.

INDEX TO EXHIBITS

 

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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.

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of February 26, 2016, by the following persons on behalf of the registrant and in the capacities indicated.

 

 

 

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