Shell Midstream Partners, L.P. - Annual Report: 2014 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2014

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. ¨  Yes    x  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.  x

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 registrant completed its initial public offering on November 3, 2014. The aggregate market value of the registrant’s common units held by non-affiliates of the registrant as of December 31, 2014, was $1,882 million, based on the closing price of such units of $40.98 as reported on the New York Stock Exchange on such date. The registrant had 67,457,068 common units and 67,457,068 subordinated units outstanding as of March 24, 2015.

Documents incorporated by reference:

None

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This report includes forward-looking statements. You can identify our forward-looking statements by the words “anticipate,” “estimate,” “believe,” “budget,” “continue,” “could,” “intend,” “may,” “plan,” “potential,” “predict,” “seek,” “should,”  “would,” “expect,” “objective,” “projection,” “forecast,” “goal,” “guidance,” “outlook,” “effort,” “target” and similar expressions.

We based the forward-looking statements on our current expectations, estimates and projections about us and the industries in which we operate in general. We caution you these statements are not guarantees of future performance as they involve assumptions that, while made in good faith, may prove to be incorrect, and involve risks and uncertainties we cannot predict. In addition, we based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. Accordingly, our actual outcomes and results may differ materially from what we have expressed or forecast in the forward-looking statements. Any differences could result from a variety of factors, including the following:

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.

Current market price: For any class of units listed or admitted to trading on any national securities exchange as of any date, the average of the daily closing prices for the 20 consecutive trading days immediately prior to that date.

DOI: Department of the Interior.

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.

LNG: Liquefied natural gas.

LTIP: Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan.

Macondo well incident: The spill of hydrocarbons from the Macondo well in the Gulf of Mexico in 2010.

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. Maintenance capital expenditures do not include expansion capital expenditures or investment capital expenditures.

PHMSA: Pipeline and Hazardous Materials Safety Administration.

PPI-FG: U.S. Producer Price Index for Finished Goods.

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.

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.

SHELL MIDSTREAM PARTNERS, L.P.

TABLE OF CONTENTS

PART I

Unless the context otherwise requires, references to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” or similar expressions for time periods prior to June 30, 2014 refer to Ho-Ho, “our Predecessor” for accounting purposes, which is the crude oil pipeline system from Houston, Texas to Houma, Louisiana wholly-owned by Shell Pipeline Company LP (“SPLC”). For time periods from July 1, 2014 to prior to November 3, 2014 (the”Completion Date”), these terms refer to Zydeco Pipeline Company LLC (“Zydeco”), “our Predecessor” for accounting purposes, which is the pipeline company that was then wholly-owned by SPLC. Zydeco wholly owned Ho-Ho since July 1, 2014. For time periods subsequent to the Completion Date, these terms refer to the legal entity Shell Midstream Partners, L.P. and its subsidiaries. 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 Ho-Ho, Zydeco and the Partnership.

Items 1 and 2. BUSINESS AND PROPERTIES

Overview

Shell Midstream Partners, L.P. is a Delaware limited partnership formed on March 19, 2014, by Shell Midstream Partners GP LLC and Shell Midstream LP Holdings LLC, both wholly-owned subsidiaries of SPLC. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by the Partnership with the U.S. Securities and Exchange Commission (“SEC”) and was declared effective on October 28, 2014. On October 29, 2014, common units representing limited partner interests in Shell Midstream Partners, L.P. began trading on the New York Stock Exchange (“NYSE”) under the symbol “SHLX.” On November 3, 2014, the Partnership completed its initial public offering (the “Offering”) of 46,000,000 common units.

At the completion of the Offering and through December 31, 2014, Shell Pipeline Company LP, through Shell Midstream LP Holdings LLC, owned 21,475,068 common units and 67,457,068 subordinated units, representing an aggregate 64.6 percent limited partner interest.  Shell Pipeline Company LP also owned a 100 percent interest in Shell Midstream Partners GP LLC, our general partner, which in turn owned 2,754,084 general partner units, representing a 2 percent general partner interest.

We are a fee-based, growth-oriented master limited partnership recently 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.  These pipelines serve as key infrastructure to transport growing onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. We generate substantially all of our revenue under long-term agreements by charging fees for the transportation of crude oil and refined products through our pipelines. 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.  Please read Note 1 in Part II, Item 8. “Financial Statements and Supplementary Data” of this Annual Report on Form 10-K.

We own interests in two crude oil pipeline systems and two refined products systems. The crude oil pipeline systems, which are held by Zydeco and Mars Oil Pipeline Company (“Mars”), 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.

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Organizational Structure

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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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Our Assets and Operations

Our assets consist of the following systems:

Zydeco System

General. Zydeco was formed by SPLC in January 2014 to own what was then called the Ho-Ho Pipeline (now Zydeco). 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 Pipeline System

Zydeco spans over 350 miles and currently has a mainline capacity of approximately 360 kbpd. Following the completion of the pending expansion, which is expected to occur before the end of 2015, Zydeco will have a mainline capacity of approximately 375 kbpd. Zydeco consists of four main segments: the Houston, Texas to Port Neches, Texas segment, which has a capacity of 250 kbpd, the Port Neches, Texas to Houma, Louisiana segment, which has a capacity of 360 kbpd (expanding to 375 kbpd upon completion of the expansion projects described below), the Houma, Louisiana to Clovelly, Louisiana segment, which has a capacity of 400 kbpd, and the Houma, Louisiana to St. James, Louisiana segment, which has a capacity of 260 kbpd. The capacity 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 43.0% interest in Zydeco. SPLC owns the remaining 57.0% 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 the years ended December 31, 2014 and 2013, four third-party customers accounted for 66.0% and 24.0% of total Zydeco revenue.

Contracts. Zydeco is supported by FERC-approved transportation services agreements and spot contracts.  As of the completion of the Zydeco expansion projects described below, approximately 87% of the fully expanded capacity of Zydeco is subject to FERC-approved transportation services agreements with a weighted average remaining term of approximately eight 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 and over 15 delivery points serving major Gulf Coast refineries and access to storage facilities.

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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 $1.00/bbl to $2.08/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. Growing crude oil production in North America has created opportunities for Zydeco. A flow reversal of what was then called the Ho-Ho pipeline system was completed in December 2013. Zydeco now runs from Houston, Texas to market hubs in St. James and Clovelly, Louisiana and transports growing 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 also expect that Zydeco will eventually carry syncrude oil volumes arriving in the Houston market from the Canadian oil sands. 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 expect to add a new third-party connection and new tankage at Port Neches before the end of 2015.

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Mars System

General. The Mars pipeline system is a major corridor pipeline servicing a high-growth area of the offshore Gulf of Mexico, originating approximately 130 miles offshore in the deepwater Mississippi Canyon and terminating in salt dome caverns in Clovelly, Louisiana. Mars was initially constructed in 1995 and has recently undergone 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 will benefit 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 2016 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.

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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 growing 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 the year ended December 31, 2014, 69% 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, 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 recently 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 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:

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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% ownership interest in Bengal and Colonial owns a 50% 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, 2014, approximately 67% of Bengal’s capacity was subject to minimum volume commitments under ship-or-pay contracts with a weighted average remaining term of approximately two years. These contracts are renewable at the election of the shipper. 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.

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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 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, representing approximately 50% of refined petroleum products consumed in the East Coast of the United States.

Ownership and Operatorship. We own a 1.612% interest in Colonial, and SPLC owns a 14.508% 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 83.880% 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 2014, 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.

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Pipeline Systems

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

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 with a combined refining capacity over 1.6 million barrels per day. 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 Zydeco, Mars and Colonial.

SPLC is Shell’s principal midstream subsidiary in the United States. SPLC owns our general partner, a significant 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 face competition from a variety of alternative transportation methods including rail, water borne movements including barging, shipping and imports and other pipelines that service the same origins or destinations as our pipelines.

Our offshore crude oil pipeline is partially supported by life-of-lease dedications. However, our offshore pipeline 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 pipeline includes 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 pipeline 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 pipeline is 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.

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Pipeline Control Operations

The pipeline 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 Common Carrier Regulations

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

FERC regulates interstate transportation on our common carrier pipeline systems under the Interstate Commerce Act 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 that 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 pending audit of Colonial. Currently, FERC is auditing Colonial in Docket No. FA14-4. No adverse findings have been reported by the auditors to date. Because FERC’s audit is ongoing, final findings and recommendations are not known at this time.

Additionally, EPAct deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” 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 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. During the five-year period commencing July 1, 2011 and ending June 30, 2016, common carriers charging indexed rates are permitted to adjust their indexed ceilings annually by PPI-FG plus 2.65%. We cannot predict whether or to what

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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. 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’s Ho-Ho pipeline; and the Louisiana Public Service Commission, which currently regulates Mars and Colonial. 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.

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 the state agency could order reparations.

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.

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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 (“PSA”), which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in HCAs. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act (“APSPA”), 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 (“PSI Act”) 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 (“PIPES Act”), 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 Part 195); pressure testing of new pipelines (Subpart E of 49 CFR Part 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 Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR Part 195); and integrity management (IM) requirements for pipelines in HCAs (49 CFR § 195.452). In addition, on October 18, 2010, PHMSA issued an advance notice of proposed rulemaking on a range of topics relating to the safety of crude oil and other hazardous liquids pipelines. Among other items, the advance notice of proposed rulemaking requested comment on whether to extend regulation to certain pipelines currently exempt from federal safety regulations; whether to extend integrity management regulations to additional pipelines or to include additional pipelines in HCAs; and whether to require emergency flow-restricting devices and revise valve spacing requirements for new or existing pipelines. PHMSA continues to evaluate the public comments received with respect to more stringent integrity management programs. In January 2015, the federal government announced a broad plan to reduce methane emissions from the oil and natural gas sector, part of which requires PHMSA to propose pipeline safety standards in 2015 that will result in reduced methane emissions.

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, but we do not anticipate that 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 high resolution internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent integrity assessments. 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. We continually monitor, test, and record the effectiveness of these corrosion inhibiting systems.

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

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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 generally, 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 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 (“RFS2”). 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 January 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.  In April 2014, the EPA released a set of five white papers analyzing methane emissions from the oil and gas industry and, based on responses received, announced in January 2015 that it plans to issue a rule governing methane emissions from oil and gas sources in summer 2015.

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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 (NSR/PSD) 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. 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. 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 SPLC’s facilities or operations, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding the additional measures and how they will be implemented.

Waste Management and Related Liabilities. To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control pollution of the environment. These laws generally regulate the generation, storage, treatment, transportation, and disposal of solid and hazardous waste. They also require corrective action, including investigation and remediation, at a facility where such waste may have been released or disposed.

CERCLA. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), which is also known as Superfund, and comparable state laws impose liability, without regard to fault or to the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the former and present owner or operator of the site where the release occurred and the transporters and generators of the hazardous substances found at the site.

Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. In the course of our ordinary operations, we generate waste that falls within CERCLA’s definition of a “hazardous substance” and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites. Pursuant to our 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 $500,000 per claim and aggregate monetary cap of $15 million for all environmental, title and litigation claims, for spills and releases, if any, existing but unknown at the time of closing of the Offering to the extent such existing but unknown spills and releases are identified within three years after closing of the Offering.

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

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before November 3, 2014 the closing date of the Offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of the Offering and identified prior to the third anniversary of the closing of the Offering, and will be subject to an aggregate deductible of $500,000 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 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 Offering 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.

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.

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.

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Insurance

All our assets other than Mars are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes 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 and Bengal’s pipelines are operated by SPLC’s employees pursuant to operating and maintenance agreements with the entities that own such pipelines. Colonial is managed by its board of directors and operated by its employees. Employees of Colonial operate Bengal’s tankage. Please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance —Management of Shell Midstream Partners, L.P.”

Website  

Our Internet website address is http://www.shellmidstreampartners.com. Information contained on our Internet website is not part of this Annual Report on Form 10-K. 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, Mars, Bengal 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, please read 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.”

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 facility, 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 terms of any such 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.

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

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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 become unavailable to transport, produce, refine or store crude oil or refined products, 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. 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 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 (“DOI”) 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 products 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 shipping 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.

Any significant decrease in production of crude oil in our areas of operation could reduce the volumes of crude oil we transport, which could adversely affect our revenue and available cash.

Our crude oil pipelines depend on the continued availability of crude oil production and reserves, particularly in the Gulf of Mexico. Low prices for crude oil or regulatory limitations could adversely affect development of additional reserves and production that are accessible by our assets. In addition, production from existing areas with access to those pipeline 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

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crude oil transported, or throughput, on our pipelines and cash flows associated with the transportation 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.

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 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 and other factors driving the demand for crude oil and refined products, including competition from alternative energy sources and the impact of new and more stringent regulations and standards affecting the exploration, production and refining industries.

If the demand for 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, which caused our customers to reduce production of refined products at their refineries, 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 business, results of operations, financial condition or cash flows, including our ability to make 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 are insured at the entity level for certain property damage, business interruption and third-party liabilities, which includes pollution liabilities. Mars is self-insured by its current owners. We carry commercial insurance for our pro rata portion of Mars’ potential liabilities, which will increase our general and administrative expenses. We do not carry named windstorm insurance for Mars, most 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.

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. For certain of our pipelines, we also 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 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.

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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, such as by adding horsepower, pump stations or new connections. For example, we expect to complete several expansion projects, including Zydeco expansion with the addition of a new third-party connection and new tankage at Port Neches before the end of 2015. These expansion projects involve numerous regulatory, environmental, political and legal uncertainties, most of which are beyond our control. If these expansion projects are not completed on schedule, certain agreements that we have entered into in anticipation of these 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 Pipeline and Hazardous Materials Safety Administration (“PHMSA”) of the U.S. Department of Transportation (“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.

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:

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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, in January 2015, the federal government announced a broad plan to reduce methane emissions from the oil and natural gas sector, part of which requires PHMSA to propose pipeline safety standards in 2015 that will result in reduced methane emissions.

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.

PHMSA is also reviewing the risks and requirements that affect a pipeline reversal, such as the Ho-Ho flow reversal. Should additional requirements be imposed, we could incur additional costs related to Zydeco and Zydeco’s cash distributions may be adversely affected.

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 U.S. Environmental Protection Agency (“EPA”) has, in recent years, adopted final rules making more stringent the National Ambient Air Quality Standards (“NAAQS”) for ozone, sulfur dioxide and nitrogen dioxide, 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.

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.

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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.

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.

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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 were constructed over many decades. Pipelines are generally long-lived assets, and pipeline 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 of our regulated assets are subject to review 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 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 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. We may at any time also be required to respond to governmental requests for information, including compliance audits conducted by FERC, such as the pending audit of Colonial. Currently, FERC is auditing Colonial in Docket No. FA14-4.  No adverse findings have been reported by the auditors to date.  Because FERC’s audit is ongoing, final findings and recommendations are not known at this time.

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 Ho-Ho, on December 10, 2013, SPLC filed three related tariffs with FERC to establish rates for uncommitted service on Ho-Ho. The filed rates became effective on December 12, 2013 and were jointly protested in a FERC filing by Anadarko Petroleum Corporation, ConocoPhllips 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 Ho-Ho, 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. The Zydeco rates are allowed to be collected subject to refund and reduction of future tariff rates pending the outcome of a hearing at FERC to determine whether the initial uncommitted (or non-contract) rates are just and reasonable. At this stage, we do not have sufficient information to estimate what amount, if any, Zydeco will be required to refund tariff payments previously made or reduce tariffs that are the subject of this protest.

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

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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 facility could adversely affect our business, financial condition, results of operations, ability to make cash distributions to our unitholders and the value of our units.

We will be dependent upon the earnings and cash flows generated by our operations in order to meet any debt service obligations and to allow us to make cash distributions to our unitholders. We have a revolving credit facility with an affiliate of Shell with $300 million in available capacity, under which no amounts were drawn as of December 31, 2014. Restrictions in our revolving credit facility and any future financing agreements could restrict our ability to finance our future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders.

The restrictions in our revolving credit facility 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 facility 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. Please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Capital Resources and Liquidity — Revolving Credit Facility Agreements” for additional information about our revolving credit facility.

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

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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. 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 consist of partial ownership interests in Zydeco, Mars, Bengal and Colonial. If a sufficient amount of our assets, or other assets acquired in the future, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we may have to register as an investment company under the Investment Company Act, claim an exemption, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates. The occurrence of some or all of these events would adversely affect the price of our common units and could have a material adverse effect on our business, results of operations, financial condition or cash flows, including our ability to make cash distributions to our unitholders.

Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Shell, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to the detriment of us and our unitholders. Additionally, we have no control over the business decisions and operations of Shell, and it is under no obligation to adopt a business strategy that favors us.

As of December 31, 2014, SPLC owned a 64.6% 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 Offering) and external financing sources, including borrowings under our revolving credit facility 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 facility restricts our ability to incur additional debt including the issuance of debt securities, except for incurring bank loans up to $600 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 facility 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.

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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:

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.

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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. 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% 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% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be used to vote on any matter.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. For example, unlike holders of stock in a public corporation, unitholders will not have “say-on-pay” advisory voting rights. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the member of our general partner, which is a wholly owned subsidiary of SPLC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

Unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of the offering 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, 2014, our general partner and its affiliates owned 31.8% of our common units and all of our subordinated units, representing an aggregate 64.6% 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% 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.

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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:

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, 2014, 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% 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, 2014, our general partner and its affiliates owned approximately 31.8% of our common units.

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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%, in addition to distributions paid on its 2% general partner interest) for each of the prior four consecutive fiscal quarters (and the aggregate amounts distributed in respect of such four-quarter period did not exceed adjusted operating surplus for such four-quarter period), to reset the minimum quarterly distribution and the initial target distribution levels at higher levels based on our cash distribution at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution per unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”), and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution. Our general partner has the right to transfer the incentive distribution rights at any time, in whole or in part, and any transferee holding a majority of the incentive distribution rights shall have the same rights as our general partner with respect to resetting target distributions.

In the event of a reset of the minimum quarterly distribution and the target distribution levels, the holders of the incentive distribution rights will be entitled to receive, in the aggregate, the number of common units equal to that number of common units which would have entitled the holders to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain the same percentage general partner interest in us that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal expansion projects that would not otherwise be sufficiently accretive to cash distributions per common unit. It is possible, however, that our general partner or a transferee could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued common units rather than retain the right to receive incentive distribution payments based on target distribution levels that are less certain to be achieved in the then-current business environment. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued common units to our general partner in connection with resetting the target distribution levels.

Our general partner intends to limit its liability regarding our obligations.

Our general partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement permits our general partner to limit its liability, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

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We identified material weaknesses in our internal control over financial reporting with respect to our Predecessor’s financial statements. If one or more material weaknesses persist or 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. Pursuant to the JOBS Act, our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002 for so long as we are an emerging growth company and we may take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards.

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. However, for as long as we are an “emerging growth company” under the Jumpstart Our Business Act (“JOBS Act”), our independent registered public accounting firm will not be required to attest to the effectiveness of our system of internal control over financial reporting pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. We could be an emerging growth company for up to five years. 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 will require us, among other things, to annually review and report on the effectiveness of our system of internal controls over financial reporting. We must comply with Section 404 (except for the requirement for an auditor’s attestation report) beginning with our fiscal year ending December 31, 2015. Any failure to develop, implement or maintain our effective internal controls, or the failure by the entities that are our equity investees to do so, or the failure by us or them to improve our or their 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.

Subsequently we restated our Predecessor’s combined audited financial statements as of and for the year ended December 31, 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 constitutes a material weakness.

  As a result of the material weaknesses described above, we are standardizing processes, segregating financial data within the accounting systems, and implementing 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.  However, there can be no assurance that these remediation steps will continue to be successful.

Given the difficulties inherent in the design and operation of our system of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our future conclusions about the effectiveness of our system of internal controls, and 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.

In addition, Section 107 of the JOBS Act also provides that an “emerging growth company” can take advantage of the extended transition period provided in Section 7(a)(2)(B) of the Securities Act for complying with new or revised accounting standards. In other

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words, an “emerging growth company” can delay the adoption of certain accounting standards until those standards would otherwise apply to private companies.

As an emerging growth company, we have the option to take advantage of these reporting exemptions until we are no longer an “emerging growth company.” We cannot predict if investors will find our units less attractive because we will rely on these exemptions. If some investors find our units less attractive as a result, there may be a less active trading market for our units and our trading price may be more volatile.

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. Please read Part III, Item 10 “Directors, Executive Officers and Corporate Governance.”

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes.

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

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, 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.

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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 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. 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. We are unable to predict whether any of these changes or other proposals will ultimately be enacted, 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.

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.

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

We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing or proposed Treasury Regulations. If the IRS were to challenge this method or new Treasury regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

Because a unitholder whose common units are loaned to a “short seller” to effect a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income.  

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

In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. The IRS may challenge our valuation methods and allocations of taxable income, gain, loss and deduction between our general partner and certain of our unitholders.

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% 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% 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% 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% 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 will initially own assets and conduct business in

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Louisiana and Texas. Texas imposes a franchise tax on all business entities at a maximum effective rate of 0.7% 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 Louisiana and Texas. Louisiana currently imposes 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.

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%, 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, 2014, the maximum federal income tax rate applicable to such qualified dividend income which is allocable to individuals was generally 20%. 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, under our omnibus agreement, SPLC will indemnify us for certain liabilities relating to litigation matters attributable to the ownership or operation of the assets contributed to us in connection with the Offering to the extent attributable to the period prior to the closing of the Offering.

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.” On November 3, 2014, the Partnership completed the initial public offering (the “Offering”) of 46,000,000 common units representing limited partner interests at a price to the public of $23.00 per unit, which included 6,000,000 common units issued pursuant to the exercise of the underwriters’ over-allotment option. Please read Note 3 in Part II Item 8.  “Financial Statements and Supplementary Data”for a discussion of the Offering.

As of March 24, 2015, SPLC owned all of our incentive distribution rights, 21,475,068 common units, 67,475,068 subordinated units, and 2,754,084 general partner units, (representing the 2.0 percent general partner interest), which together constitutes a 66.6 percent ownership interest in us. As of February 15, 2015, we had approximately four holders of record of our common units. In determining the number of unitholders, we consider clearing agencies and security position listings as one unitholder for each agency or listing.

The intraday high and low sales prices of our common units for the period starting October 29, 2014 and ending December 31, 2014, the date on which our units began trading on the NYSE, were a high of $41.46 and a low of $31.50.

No distributions were made to unitholders during the year ended December 31, 2014. On January 21, 2015, the board of directors of our general partner declared a cash distribution of $0.1042 per common unit for the quarter ended December 31, 2014. The distribution was paid on February 12, 2015, to unitholders of record on February 2, 2015. This amount represents the prorated minimum quarterly distribution of $0.1625 per unit, or $0.65 per unit on an annualized basis for the period from October 29, 2014 through December 31, 2014. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not have a legal obligation to distribute any particular amount per common unit.

Distributions of Available Cash

General

Our partnership agreement requires that, within 60 days after the end of each quarter, beginning with the quarter ending December 31, 2014, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

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

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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. Please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Capital Resources and Liquidity—Revolving Credit Facility Agreements”, for a discussion of the restrictions included in our revolving credit facility that may restrict our ability to make distributions.

General Partner Interest and Incentive Distribution Rights

Initially, our general partner is entitled to 2% of all quarterly distributions since our inception that we make prior to our liquidation. This general partner interest is represented by 2,754,084 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% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate amount of capital to us to maintain its 2% general partner interest.

Our general partner also currently holds incentive distribution rights that entitle it to receive increasing percentages, up to a maximum of 48%, 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% 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% general partner interest and assume that our general partner has contributed any additional capital necessary to maintain its 2% general partner interest, our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

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 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

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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 the Offering 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

For periods prior to the Offering, the following selected financial data consisted of the combined operations of our Predecessor. All financial information presented for periods after the Offering represents the consolidated results of operations, financial position and cash flows of Shell Midstream Partners, L.P. Accordingly:

For an explanation of our Predecessor, please read the introduction to Part I of this Annual Report on Form 10-K. 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 elsewhere in this Annual Report on Form 10-K.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements and notes thereto included in Item 8 of this Annual Report on Form 10-K.

Initial Public Offering

On November 3, 2014 (the “Completion Date”), the Partnership completed its Offering of 46,000,000 common units representing limited partner interests at a price to the public of $23.00 per unit, which included 6,000,000 common units issued pursuant to the full exercise of the underwriters’ over-allotment option. A registration statement on Form S-1, as amended through the time of its effectiveness, was filed by the Partnership with the SEC and was declared effective on October 28, 2014. On October 29, 2014, common units representing limited partner interests in Shell Midstream Partners, L.P. began trading on the New York Stock Exchange under the symbol “SHLX.”

The assets, liabilities and results of operations of our Predecessor prior to June 30, 2014 consist of the crude oil pipeline system Ho-Ho (now known as Zydeco). The assets, liabilities and results of operations of our Predecessor from July 1, 2014 to the Completion Date consist of Ho-Ho fixed assets and certain agreements and other fixed assets owned by SPLC and contributed to Zydeco prior to their contribution to the Partnership in connection with the Offering. Beginning July 1, 2014, we entered into an operating and management agreement with SPLC under which SPLC operates Ho-Ho and provides general management and administrative services to us. Subsequent to the Completion Date, the Partnership includes the following assets contributed by SPLC (“Contributed Assets”):

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In exchange for SPLC’s contribution of assets and liabilities to the Partnership, SPLC received:

The Partnership received net proceeds of $1,011.7 million from the sale of 46,000,000 common units, after deducting underwriting discounts and commissions, structuring fees and other offering expenses (the “Offering Costs”) of approximately $46.3 million. The Partnership: (i) made a cash distribution of $795.9 million to SPLC, in part to reimburse SPLC for capital expenditures incurred prior to the Offering related to the Contributed Assets; (ii) made a cash contribution of $115.8 million to Zydeco in exchange for additional interest in Zydeco, which Zydeco distributed to SPLC to reimburse SPLC for capital expenditures incurred prior to the Offering; and (iii) retained $100.0 million of these net proceeds for general partnership purposes, including to fund expansion capital expenditures, acquisitions and financing costs.

Partnership Overview

We are a fee-based, growth-oriented master limited partnership recently 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 growing onshore and offshore crude oil production to Gulf Coast refining markets and to deliver refined products from those markets to major demand centers. We generate the majority of our revenue under long-term agreements by charging fees for the transportation of crude oil and refined products through our pipelines. We do not engage in the marketing and trading of any commodities.

Our assets consist of the following:

How We Generate Revenue

Our 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. Many of our transportation agreements include a provision to allow us to adjust the rate annually based on the FERC index. There is no requirement to reduce the rate when the FERC index is negative.

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

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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.

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 (as defined below in Non-GAAP Measures); 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. 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 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. 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 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 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.

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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 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 Shell Midstream Partners 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 Shell Midstream Partners less maintenance capital expenditures attributable to Shell Midstream Partners, net interest paid, cash reserves and income taxes paid, plus net adjustments from volume deficiency payments attributable to Shell Midstream Partners. 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 condensed combined financial statements, such as industry analysts, investors, lenders and rating agencies, may use to assess:

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 Shell Midstream Partners 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 Our Business and Outlook

Substantially all of our revenue is derived from long-term transportation agreements with shippers, including ship-or-pay agreements and life-of-lease agreements, some of which provide a guaranteed return. We believe these long-term transportation 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. 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

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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. Except for PLA, we do not take ownership of the crude oil or refined products we transport. 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.

Prices for West Texas Intermediate crude oil were 46% lower at December 31, 2014 than they were at December 31, 2013.  Since the beginning of 2015, crude has continued to decline. 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 significant impact to throughput volumes on Zydeco and Mars, 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 Mars and Zydeco will continue to increase as significant deepwater production areas ramp up production, we execute continued debottlenecking efforts, and Zydeco brings a new connection on line (see “Factors Affecting the Comparability of Our Financial Results” and “Our Assets and Operations”). However, if crude oil prices remain weak for a sustained period, we could see a gradual impact on our transportation volumes if production coming into our systems is deferred and a related reduction in income from our allowance oil sales.  

Our throughput volumes on our refined products pipeline systems depend primarily on the volume of refined products produced at connected refineries and the desirability of our end markets. These factors in turn are driven by refining margins, maintenance schedules and market differentials. Refining margins depend on the cost of crude oil or other feedstocks and the price of refined products. These prices 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 two major maintenance projects planned for 2015.  On the Zydeco pipeline system, we are currently in the permitting stage of a directional drill project to address soil erosion over two segments of our 22 inch pipeline that crosses the Atchafalaya River in Louisiana.  If permitting is completed for work to begin this year, Zydeco expects to incur approximately $19 million in maintenance capital expenditures for that project, of which approximately $8.2 million would be attributable to the Partnership’s ownership share.  This work was budgeted for 2015 and accounted for in income and cash flow projections. We intend to finance the Partnership’s pro rata share of these expenditures from cash on hand, or by drawing down our working capital facility. If permitting is not completed in time for the work to be performed in the fourth quarter of 2015, the project will likely be postponed to the fourth quarter of 2016 to allow performance of the work during optimal weather and water conditions. In addition, Mars anticipates it will incur a several million dollar expense for maintenance of a storage cavern leased at LOOP’s Clovelly Dome Storage Terminal; Pursuant to the Omnibus Agreement, the Partnership intends to seek indemnity from SPLC for any losses incurred by SHLX in connection with the Mars project to the extent they exceed the applicable $500,000 deductible. These projects will have an impact on the Partnership’s expenses in 2015, and therefore on our cash available for distribution. In addition, there is a planned turnaround activity for a producer on the Mars pipeline system in the second quarter of 2015 which will reduce pipeline throughput and revenue. This activity was also planned for in 2015 and included in income and cash flow projections.

Customers

We transport 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

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pipelines. Our customers use our transportation 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.

Regulation

Our interstate common carrier pipelines are subject to regulation by various federal, state and local agencies. For more information on federal, state and local regulations affecting our business, please read Part I, Items 1 and 2, Business and Properties.

Acquisition Opportunities

We plan to pursue acquisitions of complementary assets from SPLC as well as 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 dropdowns from SPLC will be an important growth mechanism over the next few years. 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 and third parties should such opportunities arise. Identifying and executing acquisitions will be a key part of our strategy. However, if we do not make acquisitions on economically acceptable terms, 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.

Factors Affecting the Comparability of Our Financial Results

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

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Results of Operations

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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.

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Year ended December 31, 2014 compared to Year Ended December 31, 2013

Revenues

Total revenue increased by $88.1 million primarily due to $91.4 million in higher transportation services revenue 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. Storage services revenue decreased by $3.3 million due to reduced need for storage in 2014 after the pipeline reversal was completed and due to volume incentives that reduced rental payments. Third party transportation services revenue increased by $92.9 million due to the application of new contract rates in 2014. Related party transportation services revenue decreased by $1.5 million due to volume commitment shortfalls and lower tariff delivered volumes.  Delivered throughput volumes on Zydeco mainline segments increased by 38% and on the lower tariff other segments by 18% due to the completion of the pipeline reversal and activation of our FERC-approved transportation services agreements.

Expenses

Total costs and expenses were $26.2 million higher in the year ended December 31, 2014. Excluding the loss (gain) from disposition of fixed assets incurred in both years, total costs and expenses increased $5.2 million.

Operations and maintenance expenses decreased by $5.1 million primarily due to:

partially offset by,

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General and administrative expenses increased by $4.6 million 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 due to capital additions related to the Zydeco pipeline reversal and expansion projects. Property and other taxes increased by $1.0 million due to higher property appraisals in Louisiana and Texas associated with the Zydeco pipeline reversal.  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.

Year ended December 31, 2013 compared to Year Ended December 31, 2012

Revenues

Total revenue decreased by $20.5 million primarily due to $19.4 million in lower transportation revenue from shutting down portions of the Ho-Ho pipeline system to complete the reversal project. The transportation revenue decrease reflects a 21% reduction in mainline segment delivered volumes due to the 22-inch (Houma to Nederland/Port Neches) and 24-inch (Clovelly to Houma) lines going off line during the last five months of 2013 as compared to the same period in 2012 when the shutdown of the shorter 20-inch line (Nederland/Port Neches to East Houston) occurred. Transportation revenue in 2013 was also impacted by a decrease in the average tariff per barrel due to more short-haul, lower-priced routes compared to 2012. Allowance oil revenue decreased by $3.2 million compared to the prior year due to lower overall volumes from the Ho-Ho segment shutdowns.

Expenses

Operations and maintenance expenses increased in 2013 by $6.1 million as a result of a $10.8 million increase in maintenance expense offset by a $2.8 million decrease in operating expenses. Maintenance expenses increased primarily due to repair and remediation associated with a pipeline breach that occurred at the West Colombia pipeline segment during April 2013. Operations expenses decreased primarily due to lower power and fuel costs related to reduced throughput volumes. The West Columbia pipeline was sold in August 2013, resulting in a recognized gain on disposition of the pipeline of $20.8 million.

General and administrative expenses increased in 2013 by $1.8 million primarily due to an increase in third-party vendor costs related to the Ho-Ho reversal.

Depreciation increased in 2013 by $1.1 million due to capital additions related to the Ho-Ho reversal. Property and other taxes expenses increased in 2013 by $0.2 million due to higher property appraisals in Louisiana and Texas associated with the Ho-Ho pipeline reversal.

Capital Resources and Liquidity

Historically, our Predecessor’s sources of liquidity included cash generated from operations and funding from SPLC. Prior to the contribution of Ho-Ho fixed assets to Zydeco, our Predecessor participated in its Parent’s centralized cash management system; therefore, our Predecessor’s cash receipts were deposited in its Parent’s bank accounts, all cash disbursements were made from those accounts, and our Predecessor maintained no bank accounts dedicated solely to our assets. Thus, historically our Predecessor’s financial statements have reflected no cash balances. After July 1, 2014, we established our own cash accounts. We expect our ongoing sources of liquidity to include cash retained from the Offering and cash generated from operations and borrowings under our revolving credit facility. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions.

Revolving Credit Facility Agreements

Zydeco entered into a revolving credit facility with an affiliate of Shell as the lender. The facility 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 revolving credit facility agreement provides for covenants such as requiring pari passu ranking with any new

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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 revolving credit facility agreement also requires payment of customary fees, including issuance and commitment fees. The revolving credit facility matures in August 2019.

To provide additional liquidity following the Offering, we entered into a revolving credit facility agreement (the “Revolver”) with an affiliate of Shell with an initial borrowing capacity of $300.0 million. The Revolver 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 Revolver bear interest at the three-month LIBOR rate plus a margin. The 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 revolving credit facility agreement matures in October 2019. As of December 31, 2014, there is no outstanding balance.

Cash Flows from Our Operations

Operating Activities. We generated $123.6 million in cash flow from operating activities in 2014 compared to $26.0 million in 2013. The $97.6 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.

We generated $26.0 million in cash flow from operating activities in 2013, compared with $51.8 million in 2012. The decrease in cash flow from operating activities is primarily due to the decline in revenue caused by a shut-down of pipeline segments during the Ho-Ho reversal project in 2013, accompanied by an increase in operating costs due to repair and remediation associated with the West Columbia pipeline breach.

Investing Activities. Our cash flow used in investing activities was $58.3 million in 2014 compared to $82.6 million in 2013 due to lower capital expenditures related to the Zydeco pipeline. Our cash flow used in investing activities was $82.6 million in 2013, compared with $4.8 million in 2012. The increase in cash flow used in investing activities is primarily due to $105.1 million capital expenditure in 2013 related to the reversal of the Ho-Ho pipeline, offset by $22.5 million cash proceeds from the disposition of the West Columbia pipeline assets.

Financing Activities.  Our financing activities were a $84.9 million source of cash in 2014 compared to a $56.6 million source of cash in 2013. Of the $1,011.7 million net proceeds we received from the Offering in 2014, we distributed $911.7 million to our Parent. An additional $25.2 million was distributed to our Parent for its noncontrolling interest in Zydeco. Prior to July 1, 2014, all of Zydeco’s cash flow was advanced through SPLC’s centralized cash management system. As a result, we received net contributions of $12.4 million from activity prior to the Offering and for costs incurred by SPLC on our behalf. Net cash provided by financing activities for 2013 was $56.6 million as a result of contributions from SPLC, and net cash used in 2012 was $47.0 million due to distributions to SPLC.

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 will 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 for 2014 of $51.9 million. Our Predecessor’s incurred capital expenditures for 2013 was $124.7 million. The decrease in capital expenditures is primarily due to higher investment in 2013 on the Ho-Ho pipeline reversal project versus the Ho-Ho expansion and enhancement projects during 2014.

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A summary of the Partnership’s and our Predecessor’s capital expenditures, for the twelve months ended December 31, 2014, 2013 and 2012, is shown in the table below (in millions):

We have forecasted our maintenance capital expenditures, which are asset integrity projects in nature, to be approximately $23.2 million for the year ending December 31, 2015, of which approximately $19.0 million (approximately $8.2 million attributable to the Partnership) is to replace a two mile section of a 22” diameter pipe under the Atchafalaya River and Bayou Shaffer. We have forecasted our expansion capital expenditures to be $3.0 million (approximately $1.3 million attributable to the Partnership) for 2015. We anticipate that both maintenance and growth capital expenditures for the remainder of the year will be funded primarily with cash from operations.

Contractual Obligations

A summary of our contractual obligations, as of December 31, 2014, is shown in the table below (in millions):

On December 1, 2014, Zydeco entered into a terminal services agreement (the "terminal agreement") to lease three new-build storage tanks from an affiliate of Shell at the Port Neches terminal.  The terminal agreement calls for initial monthly payments of $0.4 million (the “Facility Fee”) to begin when the tanks are put in service, which is anticipated to be before the end of 2015. The 15-year terminal agreement is considered a capital lease obligation to be recognized within our financial statements once the tanks are put in service.  The terminal agreement has an option to extend for 5 years. The counterparty is entitled to an incentive payment of $100,000 per month for each month the project is delivered prior to January 2016.

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 2014.

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 read Part I, Items 1 and 2. “Business and Properties — FERC and Common Carrier Regulations.”

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

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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.

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 the combined carve-out financial statements of the Predecessor 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 our financial statements. 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 would 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 10 to 40 years. Depreciation of these assets under the straight-line method over their estimated useful lives totaled $11.6 million and $6.9 million for the years ended December 31, 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 6 — Property, Plant and Equipment to the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.

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. Although the individual assets that constitute Ho-Ho 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 any asset retirement activities. As a result, we determined that there is not sufficient information to make a reasonable estimate of the asset retirement obligation and we have not recognized any asset retirement obligations as of December 31, 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

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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.

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 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 deficiency payments is 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 sell that product several times per year at prevailing market prices.

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 condensed combined financial statements of our Predecessor 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 Part II, Item 8. “Note 12 — Commitments and Contingencies” to the consolidated financial statements and notes thereto included elsewhere in this Annual Report on Form 10-K.

Recent Accounting Pronouncements

Please read Part II, Item 8. “Note 2 — Summary of Significant Accounting Policies — Recent Accounting Pronouncements” for further details.

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 (“PLA”). 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 16% and 21% of our Predecessor’s total revenue in 2014 and 2013, 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.

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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 Shareholders of Shell Midstream Partners, L.P.:

In our opinion, 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. and its subsidiaries at December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 in conformity with accounting principles generally accepted in the United States of America.  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 audits.  We conducted our audits of these statements 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.  An audit 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 audits provide a reasonable basis for our opinion.

/s/PricewaterhouseCoopers LLP

March 24, 2015

Houston, Texas

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SHELL MIDSTREAM PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

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

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