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.

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:

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

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.

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.

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.

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.

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.

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.

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.

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

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 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.

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.

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.

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.

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:

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.

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.

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

Pipeline System	Diameter (inches)	Length (miles)		Approximate Capacity (thousands of barrels per day)
Zydeco crude oil system - Mainlines
Houston to Port Neches	20”	87		250
Port Neches to Houma	22”	213		360
Houma to Clovelly	24”	34		400
Houma to St James	18”	48		260
Mars crude oil system
Mars TLP to WD 143	18”	41		100
Olympus TLP to WD 143	18”	40		100
WD 143 to Fourchon	24”	55		400
Fourchon to Clovelly	24”	27		600
Bengal product system
Norco to Baton Rouge tank farm	24”	94		305
Convent to Baton Rouge tank farm	16”	64		210
Colonial product system	Various		5,500		2,500

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 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.

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.

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

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.

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

We are subject to regulation by PHMSA under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe, and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992 (“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.

Refined products that we transport are generally sold by our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for refined products. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the refined products in

our system and could require the construction of additional storage. If we are unable to recover these costs through increased revenue, our cash flows and ability to pay cash distributions could be adversely affected. In addition, changes in the product quality of the refined products we receive on our refined product pipeline systems or at our tank farms could reduce or eliminate our ability to blend refined products.

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.

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.

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

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.

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.

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.

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.”

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.

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.

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:

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

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

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.

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:

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.

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.

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:

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 long-term transportation agreements and tariffs for crude oil shipments include a product loss allowance. We collect product loss allowance to reduce our exposure to differences in crude oil measurement between origin and destination meters, which can fluctuate widely. This arrangement exposes us to risk of financial loss in some circumstances, including when the crude oil is received

from a ship or connecting carrier using different measurement techniques, or resulting from solids and water produced from the crude oil. It is not always possible for us to completely mitigate the measurement differential. If the measurement differential exceeds the loss allowance, the pipeline must make the customer whole for the difference in measured crude oil. Additionally, we take title to any excess product that we transport when product losses are within the allowed levels, and we sell that product several times per year at prevailing market prices. This allowance oil revenue is subject to more volatility than transportation revenue, as it is directly dependent on our measurement capability and commodity prices.

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

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

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:

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.

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.

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.

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.

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 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:

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

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.”

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.

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.

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

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.

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

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.

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.

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

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.

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.

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.

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.

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

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.

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:

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:

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

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.

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.

(in millions of dollars)	2014		2013		2012
Statements of Income
Total revenues	$	182.4	$	94.3	$	114.8
Total costs and expenses		81.1		54.9		67.7
Operating income		101.3		39.4		47.1
Income from other investments		7.5		—		—
Net income		108.4		39.3		47.0
Net income attributable to the Partnership subsequent to the Offering		13.4		—		—
Net income subsequent to the Offering per limited partner unit - Basic and Diluted:
Common	$	0.10	$	—	$	—
Subordinated	$	0.10	$	—	$	—
Cash distributions declared per unit	$	0.1042	$	—	$	—
Property, plant and equipment, net		275.0		223.5		107.4
Total assets		623.7		252.2		135.2
Equity/ Net parent investment	$	578.9	$	214.5	$	118.6

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.

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”):

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.

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 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

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.

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.

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:

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.

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.

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.

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

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.

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.

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.

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

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.

Our pipeline systems compete primarily with other interstate and intrastate pipelines and with marine and rail transportation. Some of our competitors may expand or construct transportation systems that would create additional competition for the services we provide to our customers. In addition, future pipeline transportation capacity could be constructed in excess of actual demand, which could reduce the demand for our services, in the market areas we serve, and could lead to the reduction of the rates that we receive for our services. As a result of a substantial majority of our capacity being reserved on a long-term, fixed-rate basis, our revenue is not significantly affected by variation in customers’ actual usage.

Our 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.

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.

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

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

	Year Ended December 31
(in millions of dollars)	2014		2013			2012
Revenue	$	182.4	$	94.3		$	114.8
Costs and expenses
Operations and maintenance		47.0		52.1			46.0
Loss (gain) from disposition of fixed assets		0.2		(20.8	)		1.2
General and administrative		16.8		12.2			10.4
Depreciation		11.6		6.9			5.8
Property and other taxes		5.5		4.5			4.3
Total costs and expenses		81.1		54.9			67.7
Operating income		101.3		39.4			47.1
Income from equity investments		6.7		—			—
Dividend income from investment		0.8		—			—
Income from other investments		7.5		—			—
Interest expense, net		0.2		—			—
Income before income taxes		108.6		39.4			47.1
Income tax expense		0.2		0.1			0.1
Net income		108.4	$	39.3		$	47.0
Less:
Predecessor income prior to the Offering on November 3, 2014		83.6
Net income attributable to noncontrolling interests		11.4
Net income attributable to Shell Midstream Partners, L.P.	$	13.4

Pipeline throughput (thousands of barrels per day)¹
Zydeco - Ho-Ho mainlines		487		352			448
Zydeco - Other segments		492		418			338
Zydeco total system		979		770			786
Mars total system		281		272			255
Bengal total system		506		507			463

Revenue per barrel ($ per barrel) ²
Zydeco total system	$	0.50	$	0.31		$	0.37
Mars total system		1.54		1.19			1.00
Bengal total system		0.34		0.32			0.33

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.

	Year Ended December 31
(in millions of dollars)	2014		2013			2012
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Income
Net income	$	108.4	$	39.3		$	47.0
Add:
Loss (gain) from disposition of fixed assets		0.2		(20.8	)		1.2
Allowance oil reduction to net realizable value		4.0		—			—
Depreciation and amortization		11.6		6.9			5.8
Interest expense, net		0.2		—			—
Income tax expense		0.2		0.1			0.1
Cash distribution received from equity investments — Mars		5.5		—			—
Cash distribution received from equity investments — Bengal		2.8		—			—
Less:
Income from equity investments — Mars		3.4		—			—
Income from equity investments — Bengal		3.3		—			—
Adjusted EBITDA		126.2	$	25.5		$	54.1
Less: Adjusted EBITDA attributable to Predecessor prior to the Offering on November 3, 2014		95.2
Less: Adjusted EBITDA attributable to noncontrolling interests		14.0
Adjusted EBITDA attributable to Shell Midstream Partners, L.P. subsequent to the Offering		17.0
Less:
Net interest paid attributable to the Partnership subsequent to the Offering		0.6
Income taxes paid attributable to the Partnership subsequent to the Offering		—
Zydeco maintenance capex attributable to the Partnership subsequent to the Offering		0.3
Add: Net adjustments from volume deficiency payments attributable to the Partnership subsequent to the Offering		0.4
Cash Available for Distribution attributable to Shell Midstream Partners, L.P.	$	16.5

	Year Ended December 31
(in millions of dollars)	2014			2013		2012
Reconciliation of Adjusted EBITDA and Cash Available for Distribution to Net Cash Provided by Operating Activities
Net cash provided by operating activities	$	123.6		$	26.0	$	51.8
Add:
Interest expense, net		0.2			—		—
Income tax expense		0.2			0.1		0.1
Dividend received in excess of income		1.6			—		—
Less:
Change in deferred revenue		20.0			—		—
Change in other assets and liabilities		(20.6	)		0.6		(2.2	)
Adjusted EBITDA		126.2		$	25.5	$	54.1
Less: Adjusted EBITDA attributable to Predecessor prior to the Offering on November 3, 2014		95.2
Less: Adjusted EBITDA attributable to noncontrolling interests		14.0
Adjusted EBITDA attributable to Shell Midstream Partners, L.P. subsequent to the Offering		17.0
Less:
Net interest paid attributable to the Partnership subsequent to the Offering		0.6
Income taxes paid attributable to the Partnership subsequent to the Offering		—
Zydeco maintenance capex attributable to the Partnership subsequent to the Offering		0.3
Add: Net adjustments from volume deficiency payments attributable to the Partnership subsequent to the Offering		0.4
Cash Available for Distribution attributable to Shell Midstream Partners, L.P.	$	16.5

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.

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.

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.

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.

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.

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.

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

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.

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.

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.

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.

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.

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

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

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 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.

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.

We generate the majority of our revenue under long-term transportation agreements by charging fees for the transportation of crude oil and refined products through our pipelines. Contract obligations are billed monthly. Transportation revenue is billed as services are

rendered, and we accrue revenue based on nominations for that accounting month. We estimate this revenue based on contract data, regulatory information, and preliminary throughput and allocation measurements, among other items.

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.

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.

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.

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

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.

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.

	December 31,
	2014			2013
	(in millions of dollars)
ASSETS
Current assets
Cash and cash equivalents	$	150.2		$	—
Accounts receivable - third parties, net		16.3			4.8
Accounts receivable - related parties		10.3			11.9
Allowance oil		3.4			10.0
Prepaid expenses		3.6			2.0
Total current assets		183.8			28.7
Equity method investments		160.7			—
Property, plant and equipment, net		275.0			223.5
Other assets		4.2			—
Total assets	$	623.7		$	252.2
LIABILITIES
Current liabilities
Accounts payable - third parties	$	—		$	8.4
Accounts payable - related parties		10.6			—
Distribution payable to SPLC		11.9			—
Deferred revenue - third parties		15.3			—
Deferred revenue - related parties		4.7			—
Accrued liabilities - third parties		0.9			29.3
Accrued liabilities - related parties		1.4			—
Total current liabilities		44.8			37.7
Total liabilities		44.8			37.7
Commitments and Contingencies (Note 12)
EQUITY
Common unitholders - public (46,000,000 units issued and outstanding)		1,016.2			—
Common unitholder - SPLC (21,475,068 units issued and outstanding)		(140.3	)		—
Subordinated unitholder - SPLC (67,475,068 units issued and outstanding)		(440.9	)		—
General Partner - SPLC (2,754,084 units issued and outstanding)		(18.0	)		—
Total partners' capital		417.0			—
Noncontrolling interest		161.9			—
Net parent investment		—			214.5
Total equity		578.9			214.5
Total liabilities and equity	$	623.7		$	252.2

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

	2014		2013			2012
	(in millions of dollars, except per unit data)
Revenue
Third parties	$	136.9	$	45.6		$	56.4
Related parties		45.5		48.7			58.4
Total revenue		182.4		94.3			114.8
Costs and expenses
Operations and maintenance - third parties		31.0		37.2			30.9
Operations and maintenance - related parties		16.0		14.9			15.1
Loss (gain) from disposition of fixed assets		0.2		(20.8	)		1.2
General and administrative - third parties		3.2		1.1			0.4
General and administrative - related parties		13.6		11.1			10.0
Depreciation		11.6		6.9			5.8
Property and other taxes		5.5		4.5			4.3
Total costs and expenses		81.1		54.9			67.7
Operating income		101.3		39.4			47.1
Income from equity investments		6.7		—			—
Dividend income from investment		0.8		—			—
Income from other investments		7.5		—			—
Interest expense, net		0.2		—			—
Income before income taxes		108.6		39.4			47.1
Income tax expense		0.2		0.1			0.1
Net income		108.4	$	39.3		$	47.0
Less: Predecessor income prior to the Offering on November 3, 2014		83.6
Net income subsequent to the Offering		24.8
Less: Net income attributable to noncontrolling interests		11.4
Net income attributable to Shell Midstream Partners, L.P.	$	13.4

Net income subsequent to the Offering per Limited Partner Unit - Basic and Diluted (in dollars):
Common	$	0.10
Subordinated	$	0.10

Cash distribution paid per unit (in dollars):	$	0.1042

Weighted average Limited Partner Units outstanding - Basic and Diluted (in millions):
Common units - public		46.0
Common units - SPLC		21.5
Subordinated units - SPLC		67.5

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

	2014			2013			2012
	(in millions of dollars)
Cash flows from operating activities
Net income	$	108.4		$	39.3		$	47.0
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		11.6			6.9			5.8
Loss (gain) from disposition of fixed assets		0.2			(20.8	)		1.2
Allowance oil reduction to net realizable value		4.0			—			—
Changes in operating assets and liabilities
Accounts receivable		(9.9	)		4.4			(2.1	)
Allowance oil		2.6			(4.8	)		(1.9	)
Prepaid expenses		(1.6	)		(0.5	)		(0.4	)
Accounts payable		7.0			0.7			0.2
Deferred revenue		20.0			—			—
Accrued liabilities		(18.7	)		0.8			2.0
Net cash provided by operating activities		123.6			26.0			51.8
Cash flows from investing activities
Capital expenditures		(65.0	)		(105.1	)		(4.8	)
Return of investment		1.6			—			—
Pre-Offering distribution received on behalf of SPLC		5.1			—			—
Proceeds from disposition of assets		—			22.5			—
Net cash used in investing activities		(58.3	)		(82.6	)		(4.8	)
Cash flows from financing activities
Net proceeds from Offering, net of Offering costs of $46.3 million		1,011.7			—			—
Proceeds from Offering distributed to Parent		(911.7	)		—			—
Credit facility issuance costs		(0.5	)		—			—
Distributions paid to noncontrolling interest		(25.2	)		—			—
Net contributions from Parent		12.4			—			—
Distribution of working capital to Parent		(1.8	)		56.6			(47.0	)
Net cash provided by (used in) financing activities		84.9			56.6			(47.0	)
Net increase in cash and cash equivalents		150.2			—			—
Cash at beginning of the period		—			—			—
Cash at end of the period	$	150.2		$	—		$	—
Supplemental Cash Flow Information
Non-cash investing and financing transactions:
Change in accrued capital expenditures	$	(13.1	)	$	19.6		$	10.8
Contribution of fixed assets from Parent		11.4			—			—
Amount payable to SPLC for pre-Offering distribution		(6.8	)		—			—
Contribution of investments upon Offering		166.0			—			—

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

	Partnership
(in millions of dollars)	Common Unitholders Public		Common Unitholder SPLC			Subordinated Unitholder SPLC			General Partner SPLC			Noncontrolling Interest			Net Parent Investment			Total
Balance at December 31, 2011	$	—	$	—		$	—		$	—		$	—		$	118.6		$	118.6
Net income		—		—			—			—			—			47.0			47.0
Net distributions to Parent		—		—			—			—			—			(47.0	)		(47.0	)
Balance at December 31, 2012	$	—	$	—		$	—		$	—		$	—		$	118.6		$	118.6
Net income		—		—			—			—			—			39.3			39.3
Net contributions from Parent		—		—			—			—			—			56.6			56.6
Balance at December 31, 2013	$	—	$	—		$	—		$	—		$	—		$	214.5		$	214.5
Net income from January 1, 2014 through November 2, 2014		—		—			—			—			—			83.6			83.6
Net contributions from Parent		—		—			—			—			—			12.4			12.4
Distribution of working capital to Parent		—		—			—			—			—			(1.8	)		(1.8	)
Contribution of fixed assets from Parent		—		—			—			—			—			11.4			11.4
Balance at November 2, 2014 (prior to the Offering)		—		—			—			—			—			320.1			320.1
Allocation of net parent investment to unitholders		—		32.2			101.3			4.1			182.5			(320.1	)		—
Contribution of ownership interests in equity and cost method investments		—		38.9			122.1			5.0			—			—			166.0
Net proceeds from the Offering, net of Offering costs of $46.3 million		1,011.7		—			—			—			—			—			1,011.7
Proceeds from the Offering distributed to Parent		—		(213.5	)		(670.8	)		(27.4	)		—			—			(911.7	)
Net income from November 3, 2014 through December 31, 2014		4.5		2.1			6.5			0.3			11.4			—			24.8
Distributions to non controlling interest ⁽¹⁾		—		—			—			—			(32.0	)		—			(32.0	)
Balance at December 31, 2014	$	1,016.2	$	(140.3	)	$	(440.9	)	$	(18.0	)	$	161.9		$	—		$	578.9

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

References to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” or similar expressions for time periods prior to June 30, 2014 refer to our accounting predecessor (“our Predecessor”) for accounting purposes, which is the crude oil pipeline system from Houston, Texas to Houma, Louisiana (“Ho-Ho”) wholly owned by Shell Pipeline Company LP (“SPLC”). For time periods from July 1, 2014 to prior to November 3, 2014 (the effective date of our initial public offering), these terms refer to Zydeco Pipeline Company LLC (“Zydeco”), “our Predecessor” for accounting purposes. 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 the aforementioned entities, excluding our Predecessor. References to “Mars,” “Bengal” and “Colonial” refer to Mars Oil Pipeline Company, Bengal Pipeline Company LLC and Colonial Pipeline Company, respectively, and the pipeline systems owned by those entities. See Note 3 — Initial Public Offering (“the “Offering”) for the discussion of the Offering. On November 3, 2014, we completed our Offering and our common units trade on the New York Stock Exchange under the symbol “SHLX.”

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 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, are strategically located along the Texas and Louisiana Gulf Coast and offshore Louisiana. These systems link major onshore and offshore production areas with key refining markets. The refined products pipeline systems, which are held by Bengal and Colonial, connect Gulf Coast and southeastern U.S. refineries to major demand centers from Alabama to New York.

On July 1, 2014, SPLC formed a wholly owned subsidiary named Zydeco. In anticipation of an Offering of common units by the Partnership, SPLC contributed the fixed assets and certain agreements of Ho-Ho and other related fixed assets of SPLC to Zydeco. The working capital balances of $1.8 million related to Ho-Ho as of June 30, 2014 were not contributed from SPLC to Zydeco.

We own a 43.0% interest in Zydeco, a 28.6% interest in Mars, a 49.0% interest in Bengal and a 1.612% interest in Colonial (the “Contributed Assets”). The 57.0% ownership interest in Zydeco retained by SPLC is reflected as noncontrolling interest in our consolidated financial statements. We account for each of our investments in Mars and Bengal using the equity method of accounting, and we account for our investment in Colonial using the cost method of accounting.

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

Our consolidated financial statements include all majority owned and non-majority owned subsidiaries required to be consolidated under generally accepted accounting principles in the United States (“GAAP”). Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the Securities and Exchange Commission (the “SEC”). These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification, the single source of GAAP.

These consolidated financial statements were derived from the financial statements and accounting records of our Parent. These statements reflect the consolidated historical results of operations, financial position and cash flows of our Predecessor as if such business had been a separate entity for all periods presented. Prior to July 1, 2014, intercompany transactions and accounts between our Predecessor and SPLC have been reflected as “Net parent investment” in the consolidated balance sheets. The assets and liabilities in these consolidated financial statements have been reflected on our Parent’s historical cost basis, as immediately prior to the Offering, all of the assets and liabilities presented were transferred to the Partnership within our Parent’s consolidated group in a transaction under common control. The consolidated statements of income also include expense allocations to our Predecessor prior to July 1, 2014 for certain functions historically performed by our Parent, including allocations of general corporate expenses related to finance, legal, information technology, human resources, communications, ethics and compliance, shared services, employee benefits and incentives, insurance, and share-based compensation. The portions of expenses that are specifically identifiable were directly expensed to our Predecessor, with the remainder allocated on the basis of fixed assets, headcount, labor or other measure. Our management believes the assumptions underlying the consolidated financial statements, including the assumptions regarding allocation of expenses from our Parent, are reasonable. Nevertheless, the consolidated financial statements may not include all of the expenses that would have been incurred had we been a stand-alone company during the periods presented and may not reflect our consolidated statements of income, financial position and cash flows had we been a stand-alone company during the periods presented. Beginning from July 1, 2014, Zydeco, our Predecessor, entered into an operating and management agreement with SPLC under which SPLC provides general management and administrative services to us. Therefore, we no longer receive allocated corporate expenses from SPLC. We will continue to receive direct and allocated field and regional expenses from SPLC including payroll expenses not covered under the operating and management agreement. See details of related party transactions in Note 9 — Related Party Transactions.

Prior to the contribution of fixed assets and certain agreements on July 1, 2014, the cash generated and used by our operations was deposited to SPLC’s centralized account which was comingled with the cash of other pipeline entities controlled by SPLC. SPLC funded our operating and investing activities as needed. Accordingly, we did not record any cash and cash equivalents held by SPLC on our behalf for any period presented. We reflected the cash generated by our operations and expenses paid by our Parent on behalf of our operations as a component of “Net parent investment” on the accompanying consolidated balance sheets and consolidated statements of changes in equity, and as part of “Net contributions from (distributions to) Parent” on the accompanying consolidated statements of cash flows. On July 1, 2014, we established our own cash accounts for the funding of our operating and investing activities, with the exception of the capital expenditures incurred by SPLC on our behalf and then contributed to us. See Note 3 — Initial Public Offering for additional details.

All financial information presented for the periods after the Offering represents the consolidated statements of income, financial position and cash flows of the Partnership. Accordingly:

The Partnership generally accounts for investments in 20% to 50%-owned affiliates, and investments in less than 20%-owned affiliates where it has the ability to exercise significant influence, under the equity method. We own a 43.0% interest in Zydeco, a 28.6% interest in Mars, a 49.0% interest in Bengal and a 1.612% interest in Colonial. Accordingly, the consolidated historical financial statements for the Partnership reflect the consolidation of Zydeco (100%), and the investments in Mars and Bengal using the equity method of accounting. Our investment in Colonial is accounted for as a cost method investment.

Our consolidated financial statements include all subsidiaries where the Partnership has control. The assets and liabilities in the accompanying consolidated financial statements have been reflected on a historical basis. All significant intercompany accounts and transactions are eliminated upon consolidation. We own 43.0% of the ownership interest in Zydeco and record a noncontrolling interest for the 57.0% ownership interest retained by SPLC. We obtained control of Zydeco via the voting agreement between SPLC and us under which we have voting power over the ownership interests retained by SPLC in Zydeco.

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

In the accompanying consolidated balance sheets, Net parent investment represents SPLC’s historical investment in us, our accumulated net earnings through November 2, 2014, and the net effect of transactions with, and allocations from, SPLC and Shell Oil Company.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the accompanying consolidated financial statements and notes. Actual results could differ from those estimates.

Assets and businesses acquired from our Parent and its subsidiaries are accounted for as common control transactions whereby the net assets acquired are combined with ours at their historical costs. If any recognized consideration transferred in such a transaction exceeds the carrying value of the net assets acquired, the excess is treated as a capital distribution to our General Partner, similar to a dividend. If the carrying value of the net assets acquired exceeds any recognized consideration transferred including, if applicable, the fair value of any limited partner units issued, then that excess is treated as a capital contribution from our General Partner. To the extent that such transactions require prior periods to be recast, historical net equity amounts prior to the transaction date are reflected in “Net Parent Investment.” Cash consideration up to the carrying value of net assets acquired is presented as an investing activity in our consolidated statement of cash flows. Cash consideration in excess of the carrying value of net assets acquired is presented as a financing activity in our consolidated statement of cash flows.

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

As a result of FERC regulations, revenues we collect may be subject to refund. We establish reserves for these potential refunds based on actual expected refund amounts on the specific facts and circumstances. We had no reserves for potential refunds as of December 31, 2014 and 2013.

Our FERC-approved transportation services agreements on Zydeco entitle the customer to a specified amount of guaranteed capacity on a pipeline. This capacity cannot be pro-rated even if the pipeline is oversubscribed. In exchange, the customer makes a specified monthly payment regardless of the volume transported. If the customer does not ship its full guaranteed volume in a given month, it makes the full monthly cash payment and may ship the unused volume in a later month for no additional cash payment for

up to 12 months, subject to availability on the pipeline. If there is insufficient capacity on the pipeline to allow the unused volume to be shipped, the customer forfeits its right to ship such unused volume.

Cash collected from customers for shortfalls under these agreements are recorded as deferred revenue. The Company recognizes deferred revenue under these arrangements into revenue once all contingencies or potential performance obligations associated with the related volumes have either (1) been satisfied through the transportation of future excess volumes of crude oil, or (2) expired (or lapsed) through the passage of time pursuant to the terms of the FERC-approved transportation services agreement. Because the expiration of a customer’s right to utilize shortfall payments is twelve months or less, we classify deferred revenue as a short term liability. Deferred revenue balance was $20.0 million and zero as of December 31, 2014 and 2013, respectively.

Our long-term transportation agreements and tariffs for crude oil transportation include a product loss allowance, or “PLA.” PLA is intended to assure proper measurement of the crude oil despite solids, water, evaporation and variable crude types that can cause mismeasurement. The PLA provides additional revenue for us if product losses on our pipelines are within the allowed levels, and we are required to compensate our customers for any product losses that exceed the allowed levels. We take title to any excess loss allowance when product losses are within an allowed level, and we convert that product to cash several times per year at prevailing market prices to a related party.

For the years ended December 31, 2014, 2013 and 2012, our transportation services revenue from third parties was $136.8 million, $43.9 million and $56.4 million, respectively; our transportation services revenue from related parties was $42.0 million $43.5 million and $52.6 million, respectively; our storage services revenues from third parties were $0.1 million, $1.7 million and zero, respectively; our storage services revenues from related parties was $3.5 million, $5.2 million and $5.8 million, respectively.

Accounts receivable represent valid claims against customers for products sold or services rendered, net of allowances for doubtful accounts. We assess the creditworthiness of our counterparties on an ongoing basis and require security, including prepayments and other forms of collateral, when appropriate. We establish provisions for losses on accounts receivable due from shippers and operators if we determine that we will not collect all or part of the outstanding balance. Outstanding customer receivables are regularly reviewed for possible nonpayment indicators, and allowances for doubtful accounts are recorded based upon management’s estimate of collectability at each balance sheet date. As of December 31, 2014 and 2013, our allowance for doubtful accounts was not material.

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

For the twelve months ended December 31, 2014, we reduced the net realizable value of allowance oil by $4.0 million. As of December 31, 2014 and 2013, allowance oil on the balance sheet was $3.4 million and $10.0 million, respectively. Gains and losses from the conversion of allowance oil to cash and gains and losses from pipeline operations that relate to allowance oil are recorded in Operations and maintenance expenses in the accompanying consolidated statements of income. During the fourth quarter of 2014, we made a sale of allowance oil at prevailing market prices to a Parent affiliate. See Note 9 — Related Party Transactions for more details.

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets. Amortization expense of less than $0.1 million related to equity method

investments is in the accompanying consolidated statement of income for the year ended December 31, 2014. As of December 31, 2014, the equity investment exceeded our equity in the net assets of Mars and Bengal by approximately $12.0 million and $6.3 million.

Our property, plant and equipment is recorded at its historical cost of construction or, upon acquisition, at either the fair value of the assets acquired or the cost to the entity that placed the asset in service. Expenditures for major renewals and betterments are capitalized while those minor replacement, maintenance, and repairs which do not improve or extend asset life are expensed when incurred. For constructed assets, we capitalize all construction-related direct labor and material costs, as well as indirect construction costs.

We use the straight-line method to depreciate property, plant and equipment based on the estimated useful life of the asset. We report gains or losses on dispositions of fixed assets as Loss (gain) from disposition of fixed assets in the accompanying consolidated statements of income.

We evaluate long lived assets of identifiable business activities for impairment when events or changes in circumstances indicate, in our management’s judgment, that the carrying value of such assets may not be recoverable. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset and adverse changes in the legal or business environment such as adverse actions by regulators. If an event occurs, which is a determination that involves judgment, we evaluate the recoverability of our carrying values based on the long-lived asset’s ability to generate future cash flows on an undiscounted basis. When an indicator of impairment has occurred, we compare our management’s estimate of forecasted discounted future cash flows attributable to the assets to the carrying value of the assets to determine whether the assets are recoverable (i.e. the discounted future cash flows exceed the net carrying value of the assets). If the assets are not recoverable, we determine the amount of the impairment recognized in the financial statements by estimating the fair value of the assets and recording a loss for the amount that the carrying value exceeds the estimated fair value. We determined that there were no asset impairments in the years ended December 31, 2014, 2013 or 2012.

We are not a taxable entity for U.S. federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income are generally borne by our partners through the allocation of taxable income. Our income tax expense results from partnership activity in the state of Texas, as conducted by Zydeco. Income taxes for the years ended December 31, 2014, 2013, and 2012 were $0.2 million, $0.1 million and $0.1 million, respectively.

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

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

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

asset retirement obligations for our assets and we have not recognized any asset retirement obligations as of December 31, 2014 and 2013.

We do not have our own employees. Employees that work on our pipeline are employees of SPLC and we share employees with other SPLC-controlled and non-controlled entities. For presentation of these accompanying consolidated financial statements, our portion of payroll costs and employee benefit plan costs have been allocated to us as a charge to us by SPLC and Shell Oil Company. Shell Oil Company sponsors various employee pension and postretirement health and life insurance plans. For purposes of these accompanying consolidated financial statements, we are considered to be participating in the benefit plans of Shell Oil Company. We participate in the following defined benefits plans: Shell Oil Pension Plan, Shell Oil Retiree Health Care Plan, and Pennzoil-Quaker State Retiree Medical & Life Insurance. As a participant in these benefit plans, we recognize as expense in each period an allocation from Shell Oil Company, and we do not recognize any employee benefit plan assets or liabilities. See Note 9 — Related Party Transactions for total pension and benefit expenses under these plans.

We are subject to litigation and regulatory proceedings as the result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments or settlements. In general, we expense legal costs as incurred. When we identify specific litigation that is expected to continue for a significant period of time, is reasonably possible to occur and may require substantial expenditures, we identify a range of possible costs expected to be required to litigate the matter to a conclusion or reach an acceptable settlement, and we accrue for the lower end of the range. To the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected.

We are subject to federal, state, and local environmental laws and regulations. Environmental expenditures are expensed or capitalized depending on their economic benefit. We expense costs such as permits, compliance with existing environmental regulations, remedial investigations, soil sampling, testing and monitoring costs to meet applicable environmental laws and regulations where prudently incurred or determined to be reasonably possible in the ordinary course of business. We are permitted to recover such expenditure through tariff rates charged to customers. We also expense costs that relate to an existing condition caused by past environmental incidents, which do not contribute to current or future revenue generation. We discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs. Generally, our recording of these accruals coincides with our completion of a feasibility study or our commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We do not use regulatory accounting principles.

For the years ended December 31, 2014, 2013 and 2012, we incurred $3.0 million, $13.6 million and zero environmental cleanup costs. Due to the formation of Zydeco via the contribution of fixed assets and certain agreements from SPLC, Zydeco was indemnified by SPLC against environmental cleanup costs for incidents that occurred prior to Zydeco’s formation on July 1, 2014. In 2013, the West Columbia pipeline experienced a breach in which approximately 940 barrels of oil released in the vicinity of the pipeline. During 2013, we incurred $12.1 million in costs primarily related to several large maintenance projects for the containment of this incident at the West Columbia pipeline. As of December 31, 2014 and December 31, 2013, we accrued zero and $2.8 million, respectively, for environmental clean-up costs. Refer to Note 3 — Initial Public Offering under the Omnibus Agreement for additional details.

We routinely conduct reviews of potential environmental issues and claims that could impact our assets or operations. These reviews assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us and potential third-party liability claims. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs. These revisions are reflected in our income in the period in which they are probable and reasonably estimable.

We recognize liabilities for other contingencies when we have an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably

estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

We measure assets and liabilities requiring fair value presentation or disclosure using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability) and disclose such amounts according to the quality of valuation inputs under the following hierarchy:

Level 2: Inputs other than quoted prices that are directly or indirectly observable.

Level 3: Unobservable inputs that are significant to the fair value of assets or liabilities.

We classify the fair value of an asset or liability based on the lowest level of input significant to its measurement. A fair value initially reported as Level 3 will be subsequently reported as Level 2 if the unobservable inputs become inconsequential to its measurement, or corroborating market data becomes available. Asset and liability fair values initially reported as Level 2 will be subsequently reported as Level 3 if corroborating market data becomes unavailable.

The carrying amounts of our accounts receivable, accounts payable, accrued liabilities and revolving credit agreements approximate their carrying values due to their short term nature.

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

Net income per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income for the period subsequent to the Offering by the weighted average number of common units and subordinated units, respectively, outstanding for the period. Because we have more than one class of participating securities, we use the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, and incentive distribution rights. Basic and diluted net income per unit are the same because we do not have any potentially dilutive units outstanding for the period presented.

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

In April 2014, the FASB issued accounting standards updates to Topic 205, “Presentation of Financial Statements” and to Topic 360, “Property, Plant, and Equipment” to change the criteria for reporting discontinued operations. The amendments modify the definition of discontinued operations by limiting discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity’s operations and financial results. These amendments require additional disclosures about discontinued operations and new disclosures for other disposals of individually material components of an organization that do not meet the definition of a discontinued operation. In addition, the guidance allows companies to have significant continuing involvement and continuing cash flows with the discontinued operation. These provisions are effective prospectively for annual reporting periods beginning on or after December 15, 2014, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance, effective January 1, 2015, will not affect our financial position or results of operations; however, it may result in changes to the manner in which future dispositions of operations or assets, if any, are presented in our consolidated financial statements, or it may require additional disclosures.

In May 2014, the FASB and the International Accounting Standards Board (“IASB”) issued a new accounting standard, Topic 606, “Revenue from Contracts with Customers,” to clarify the principles for recognizing revenue. The core principle of the new standard is that an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard also requires improved

interim and annual disclosures that enable the users of financial statements to better understand the nature, amount, timing, and uncertainty of revenues and cash flows arising from contracts with customers. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. We are currently evaluating the effect that adopting this new standard will have on our consolidated financial statements and related disclosures.

In August 2014, the FASB issued accounting standards update, Subtopic 205-40, “Presentation of Financial Statements—Going Concern,” requiring management to evaluate whether events or conditions could impact an entity's ability to continue as a going concern within one year after the date that the financial statements are issued (or available to be issued) and to provide disclosures if necessary. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management's plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted. The adoption of this guidance will not affect our financial position or results of operations.

In November 2014, the FASB issued ASU 2014-17 that gives acquired entities that are businesses or nonprofit activities the option to apply pushdown accounting in their separate financial statements when an acquirer obtains control of them. The adoption of this guidance, effective November 18, 2014, will not affect our financial position or results of operations.

In January 2015, the FASB issued accounting standards update, Subtopic 225-20, “Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items,” The adoption of this guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015, with early adoption permitted. The adoption of this guidance will not affect our financial position or results of operations.

In February 2015, the FASB issued accounting standards updates to topic 810, “Consolidation” to change the criteria for reporting entities that are required to evaluate whether they should consolidate certain legal entities. The amendments require additional testing to determine if a legal entity qualifies as a Variable Interest Entity and whether the entity should be consolidated. These provisions are effective prospectively for annual reporting periods beginning on or after December 15, 2015, and interim periods within those annual periods, with early adoption permitted. The adoption of this guidance will not affect our financial position or results of operations.

On November 3, 2014, 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 exercise of the underwriters’ over-allotment option. The Partnership received net proceeds of $1,011.7 million from the sale of 46,000,000 common units, after deducting 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. In exchange for SPLC’s contribution of assets and liabilities to the Partnership, SPLC received: a) 21,475,068 common units and 67,475,068 subordinated units, representing an aggregate 64.6% limited partner interest in us; b) all of our incentive distribution rights; c) 2,754,084 general partner units, representing a 2.0% general partner interest; and d) a cash distribution of $911.7 million. 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, Shell Midstream Partners, L.P. common units began trading on the New York Stock Exchange under the symbol “SHLX.”

On July 1, 2014, Zydeco entered into a contribution agreement with SPLC. As part of that agreement, SPLC contributed the fixed assets of $249.3 million and certain agreements of the Predecessor and other fixed assets of SPLC of $11.4 million to Zydeco in exchange for 100.0% of the equity in Zydeco. The working capital balances of $1.8 million related to the Predecessor were not contributed as part of this agreement from SPLC to Zydeco. From July 1, 2014 until the Offering, capital expenditures of $16.5 million were incurred by SPLC on behalf of Zydeco and then contributed to Zydeco as an additional investment. Subsequent to the Offering, Zydeco reimburses SPLC for capital expenditures incurred by SPLC on behalf of Zydeco.

In connection with the Offering, the Partnership entered into an Omnibus Agreement with SPLC and our general partner that addresses the following matters:

Upon the formation of Zydeco on July 1, 2014, Zydeco entered into an operating and management agreement with SPLC. Zydeco reimburses SPLC for certain operational costs such as labor, contract services and materials and supplies. Zydeco also pays an annual management fee, initially $7.0 million, to SPLC for general management and administrative services.

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

Accounts receivable from third parties consist of the following at December 31 (in millions of dollars):

The reduction in allowance for doubtful accounts in 2014 is due to SPLC not contributing working capital balances to Zydeco on July 1, 2014.

As of December 31, 2014, our equity method investments consist of 28.6% interest in Mars and 49.0% interest in Bengal. The equity method investment balances as of December 31, 2014 for Mars and Bengal are $85.7 million and $75.0 million, respectively. The net income earned from equity method investments for the period November 3, 2014 through December 31, 2014 for Mars and Bengal are $3.4 million and $3.3 million, respectively.

The following tables present aggregated selected balance sheet and income statement data for our equity method investments Mars and Bengal (on a 100% basis) for all periods presented:

	November 3 - December 31, 2014
	Mars		Bengal		Total
Statements of Income
Total revenues⁽¹⁾	$	—	$	—	$	—
Total operating expenses⁽¹⁾		—		—		—
Operating income⁽¹⁾		—		—		—
Net income		11.9		6.6		18.5
Balance Sheets
Current assets	$	38.3	$	35.9	$	74.2
Non-current assets		214.0		146.7		360.7
Total assets	$	252.3	$	182.6	$	434.9
Current liabilities		6.1		19.0		25.1
Non-current liabilities		—		1.2		1.2
Equity		246.2		162.4		408.6
Total liabilities and equity	$	252.3	$	182.6	$	434.9

Property, plant and equipment consist of the following at December 31 (in millions of dollars):

			December 31,
	Depreciable Life		2014			2013
Land		—	$	1.1		$	0.7
Building and improvements	10 - 40 years			10.5			8.2
Pipeline and equipment	10 - 30 years			313.6			257.0
Other	5 - 25 years			5.5			5.2
				330.7			271.1
Less: Accumulated depreciation				(66.5	)		(54.8	)
				264.2			216.3
Construction in progress				10.8			7.2
Property, plant and equipment, net			$	275.0		$	223.5

Depreciation expense on property, plant and equipment of $11.6 million, $6.9 million and $5.8 million is included in cost and expenses in the accompanying consolidated statements of income for the years ended December 31, 2014, 2013 and 2012, respectively.

In August 2013, we sold to Magellan Midstream Partners (“Magellan’) our West Columbia pipeline in east Houston, a 16-inch diameter crude oil pipeline that is approximately 15 miles long and originates at Genoa Junction and terminates at Magellan’s crude oil and refined products distribution terminal in East Houston, Texas. We recorded a $20.8 million gain related to the sale.

Accrued liabilities consist of the following at December 31 (in millions of dollars):

On November 3, 2014, the Partnership entered into a $300.0 million senior unsecured revolving credit facility agreement (the “Revolver”) with Shell Treasury Center (West) Inc., an affiliate of Shell. The Revolver matures in October 2019 and contains certain restrictive covenants. The Revolver contains representations and warranties, covenants such as restricting additional indebtedness above $600 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 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 Partnership paid a credit facility issuance fee of $0.5 million which was capitalized and will be amortized over the five year term of the facility. As of December 31, 2014, the amount of credit facility issuance costs in Other assets is $0.5 million. For the year ended December 31, 2014, interest and fee expenses were approximately $0.1 million. During 2014, there were no borrowings under the Revolver. As of December 31, 2014, there were no borrowings outstanding under the Revolver.

In August 2014, Zydeco entered into a senior unsecured revolving credit facility agreement (the ‘Zydeco Revolver”) 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 Zydeco Revolver provides for covenants such as requiring pari passu ranking with any new indebtedness and contains customary events of default, such as nonpayment of principal when due, nonpayment of interest, fees or other amounts, violation of covenants, and cross-payment default (due to indebtedness in excess of $100 million). The Zydeco Revolver also requires payment of customary fees, including issuance and commitment fees and matures in August 2019.

During the six month period ending December 31, 2014, Zydeco had borrowings of $6.0 million from its revolving credit facility agreement in order to meet working capital requirements, which were repaid within two months of the withdrawal. Interest and fees incurred was approximately $0.1 million. No amount was outstanding as of December 31, 2014.

Related party transactions include transactions with our Parent and our Parents’ affiliates including those entities in which our Parent has an ownership interest but does not have control.

Prior to SPLC’s contribution of fixed assets and certain agreements to us on July 1, 2014, we participated in our Parent’s centralized cash management and funding system. Our working capital and capital expenditure requirements have historically been part of the corporate-wide cash management program for our Parent. As part of this program, our Parent maintained all cash generated by our operations, and cash required to meet our operating and investing needs was provided by our Parent as necessary. Net cash generated from or used by our operations is reflected as a component of “Net parent investment” on the accompanying consolidated balance sheets and as “Net contributions from (distributions to) Parent” on the accompanying consolidated statements of cash flows.

No interest income has been recognized on net cash kept by our Parent since, historically, we have not charged interest on intercompany balances. On July 1, 2014, we established our own cash accounts for the funding of our operating and investing activities. We will therefore no longer participate in our Parent’s cash management program, with the exception of the capital expenditures incurred by SPLC on our behalf and then contributed to us. From November 3 through December 31, 2014, Zydeco reimbursed SPLC for expenditures incurred on behalf of Zydeco. See Note 3 — Initial Public Offering for additional details.

Other related party balances consist of the following as of December 31 (in millions of dollars):

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

We provide crude oil transportation and storage services to related parties under long-term contracts. We entered into these contracts in the normal course of our business and the services are based on the same terms as those provided to third parties. Our transportation services revenue from related parties was $42.0 million, $43.5 million and $52.6 million for each of the years ended December 31, 2014, 2013 and 2012, respectively. In November 2014, we recorded a $0.4 million loss in Operations and maintenance – related parties from converting excess allowance oil to cash by selling the allowance oil to an affiliate of our Parent. Revenues related to storage services from related parties were approximately $3.5 million, $5.2 million and $5.8 million for each of the years ended December 31, 2014, 2013 and 2012, respectively.

During the three month period ending December 31, 2014, the Partnership received cash distributions of $33.3 million in total from Zydeco, Mars, Bengal and Colonial, of which $19.0 million related to Zydeco. In accordance with the Partnership agreement which became effective on November 3, 2014, the pro rata share of the distributions prior to the effective date are owed to SPLC. The amount of the Distribution payable to SPLC is $11.9 million, of which $6.8 million relates to Zydeco.

Prior to SPLC’s contribution of certain fixed assets and agreements to Zydeco on July 1, 2014, our Parent performed certain services which directly and indirectly supported our operations. Personnel and operating costs incurred by our Parent on our behalf were charged to us and are included in either general and administrative expenses or operations and maintenance expenses in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations. Our Parent also performs certain general corporate functions for us related to finance, legal, information technology, human resources, communications, ethics and compliance, and other shared services. During the six months ended June 30, 2014, and the years ended December 31, 2013 and 2012, we were allocated $6.8 million, $11.1 million and $10.0 million, respectively, of indirect general corporate expenses incurred by our Parent which are included within general and administrative expenses in the accompanying consolidated statements of income. These allocated corporate costs relate primarily to the wages and benefits of our Parent’s employees that support our operations. Expenses incurred by our Parent on our behalf have been allocated to us on the basis of direct usage when identifiable. Where costs incurred by our Parent could not be determined to relate to us by specific identification, these costs were primarily allocated to us on the basis of headcount, labor or other measure. The expense allocations have been determined on a basis that both we and our Parent consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. The allocations may not, however, fully reflect the expenses we would have incurred as a separate, publicly-traded company for the periods presented. All employees performing services on behalf of our operations are employees of SPLC.

Beginning July 1, 2014, we entered into an operating and management agreement with SPLC under which SPLC provides general management and administrative services to us. We no longer receive allocated corporate expenses from SPLC, Shell Oil Company or any other Parent affiliate. We will continue to receive direct and allocated field and regional expenses including payroll expenses not covered under the operating and management agreement. These expenses are primarily allocated to us on the basis of headcount, labor or other measure. These expense allocations have been determined on a basis that both SPLC and we consider to be a reasonable reflection of the utilization of services provided or the benefit received by us during the periods presented. For the six months ended December 31, 2014, the management fee charged by SPLC under the operating and management agreement was $3.5 million.

Prior to the Offering, we were covered by the insurance policies of SPLC. Subsequent to the Offering, the majority of our coverage is provided by our Parent with the remaining coverage by third party insurers. The related party portion of insurance expense in 2014 was $3.7 million.

The following table shows related party expenses, including personnel costs described above, incurred by Shell Oil Company and SPLC on our behalf that are reflected in the accompanying consolidated statements of income for the years ended December 31 (in millions of dollars):

Employees who directly or indirectly support our operations participate in the pension, postretirement health and life insurance, and defined contribution benefit plans sponsored by our Parent, which include other Parent subsidiaries. Our share of pension and postretirement health and life insurance costs for the years ended December 31, 2014, 2013 and 2012 was $2.5 million, $3.1 million and $3.2 million, respectively. Our share of defined contribution benefit plan costs for the same periods was $1.0 million, $1.2 million and $0.9 million, respectively. Pension and defined contribution benefit plan expenses are included in either general and administrative expenses or operations and maintenance expenses in the accompanying consolidated statements of income, depending on the nature of the employee’s role in our operations.

Our Parent’s incentive compensation programs primarily consist of share awards, restricted share awards or cash awards (any of which may be a performance award). The Performance Share Plan (“PSP”) was introduced in 2005 by our Parent. Conditional awards of RDS shares are made under the terms of the PSP to some 15,000 employees each year. The extent to which the awards vest is determined over a three-year performance period. Half of the award is linked to the key performance indicators, averaged over the period. For the PSP awards made prior to 2010, the other half of the award was linked to the relative total shareholder return over the period compared with four main competitors of RDS. For awards made in 2010 and onwards, the other half of the award is linked to a comparison with four main competitors of RDS over the period on the basis of four relative performance measures. All shares that vest are increased by an amount equal to the notional dividends accrued on those shares during the period from the award date to the vesting date. None of the awards result in beneficial ownership until the shares are delivered.

Under the PSP, awards are made on a highly selective basis to senior personnel. Shares are awarded subject to a three-year vesting period.

Certain Parent employees supporting our operations as well as other RDS operations were historically granted these types of awards. These share-based compensation costs have been allocated to us as part of the cost allocations from our Parent prior to June 30, 2014 and have been immaterial. Beginning July 1, 2014, we did not receive any allocated share-based compensation. Share-based compensation expense is included in general and administrative expenses in the accompanying consolidated statements of income. These costs totaled $0.1 million for the six months ended June 30, 2014, and totaled less than $0.2 million and $0.2 million for the years ended December 31, 2013 and 2012, respectively.

We have equity method investments in entities that own certain of our assets, including Mars and Bengal. In some cases we may be required to make capital contributions or other payments to these entities. For information regarding these equity method investments, see Note 5 – Equity Method Investments for additional details.

On January 20, 2015, the Board of Directors of our general partner declared our quarterly cash distribution of $0.1042 per unit, or $14.4 million in total, for the fourth quarter of 2014. This distribution was paid on February 12, 2015, to unitholders of record as of February 2, 2015. The following table shows the allocation of net income to arrive at net income per limited partner unit:

	2014
	General Partner		Limited Partners' Common Units			Limited Partner's Subordinated Units			Total
Net income from November 3, 2014 through December 31,2014	(in millions of dollars, except per unit data)
Distributions declared	$	0.3	$	7.0		$	7.1		$	14.4
Distributions in excess of net income subsequent to the Offering		—		(0.5	)		(0.5	)		(1.0	)
Net income subsequent to the Offering	$	0.3	$	6.5		$	6.6		$	13.4
Weighted average units outstanding (in millions):
Basic		2.7		67.5			67.5			137.7
Diluted		2.7		67.5			67.5			137.7
Net income per limited partner unit (in dollars):
Basic			$	0.10		$	0.10
Diluted			$	0.10		$	0.10

The following table shows revenues from third party customers that accounted for 10% or a greater share of consolidated revenues for each of the three years ended December 31 (in millions of dollars):

Our Parent and our Parent’s affiliates accounted for 25%, 52% and 51% of our total revenues for the years ended December 31, 2014, 2013 and 2012, respectively. The following table shows accounts receivable from third party customers that accounted for 10% or a greater share of consolidated accounts receivable, net for each of the two years ended December 31 (in millions of dollars):

We have a concentration of revenues and trade receivables due from customers in the same industry, our Parent’s affiliates, integrated oil companies, and independent exploration, production and refining companies. These concentrations of customers may impact our overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. We are potentially exposed to concentration of credit risk primarily through our accounts receivable with our Parent. These receivables have payment terms of 30 days or less. We monitor the creditworthiness of our Parent, which has an investment grade credit rating and no history of collectability issues, and we monitor the creditworthiness of third-party major customers. We manage our exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. As of December 31, 2014 and 2013, there were no such arrangements.

We have concentrated credit risk for cash by maintaining deposits in a major bank, which may at times exceed amounts covered by insurance provided by the United States Federal Deposit Insurance Corporation (“FDIC”). We monitor the financial health of the bank and have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk. As of December 31, 2014, we had approximately $149.7 million in cash and cash equivalents in excess of FDIC limits.

Our Parent and certain affiliates are named defendants in lawsuits and governmental proceedings that arise in the ordinary course of our business. For each of our outstanding legal matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we do not expect that the ultimate resolution of these matters will have a material adverse effect on our financial position, operating results, or cash flows.

Under our Omnibus Agreement, SPLC will indemnify us for certain environmental liabilities, tax liabilities, litigation and other matters attributable to the ownership or operation of our assets prior to the closing of the Offering. For the purposes of determining the indemnified amount of any loss suffered or incurred by the Partnership, the Partnership’s ownership of 43.0% of Zydeco, 28.6% of Mars, 49.0% of Bengal and 1.612% of Colonial shall be taken into account. The aggregate liability of SPLC shall not exceed $15.0 million and is subject to an aggregate deductible of $0.5 million before we are entitled to indemnification.

Indemnification for any unknown environmental liabilities is limited to liabilities due to occurrences prior to the closing of the Offering and that are identified before the third anniversary of the closing of the Offering. Indemnification for losses related to right-of-way and permits, retained assets or litigation matters (other than currently pending legal actions) are limited to events reported within one year of the Closing Date. SPLC will also indemnify us for tax liabilities which are identified prior to the date that is 60

days after the expiration of the statute of limitations applicable to such liabilities. We have agreed to indemnify SPLC for events and conditions associated with the ownership or operation of our assets that occur on or after the closing of the Offering and for certain environmental liabilities related to our assets to the extent SPLC is not required to indemnify us and limited to ownership percentages.

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline systems. Obligations under these easements are not material to the results of our operations.

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 $0.1 million per month for each month the project is delivered prior to January 2016.

We are also obligated under various long-term and short-term noncancelable operating leases, primarily related to tank farm land leases. Several of the leases provide for renewal terms. Rental expense included in Operations and maintenance in the consolidated statements of income was $0.5 million for each of the years ended December 31, 2014, 2013 and 2012. As of December 31, 2014, we have the following long-term lease obligation related to a tank farm land lease (in millions of dollars):

We have evaluated events that occurred after December 31, 2014 through the issuance of these consolidated financial statements. Any material subsequent events that occurred during this time have been properly recognized or disclosed in the consolidated financial statements and accompanying notes.

(in millions of dollars, except for per unit data)	Total Revenues		Income Before Income Taxes		Net Income		Net Income Subsequent to the Offering		Limited Partners' Interest in Net Income Subsequent to Initial Public Offering ⁽¹⁾		Net Income per Common Unit Subsequent to the Offering - Basic and Diluted
2014
First	$	36.3	$	15.2	$	15.2	$	—	$	—	$	—
Second		43.6		26.6		26.6		—		—		—
Third		46.9		31.0		31.0		—		—		—
Fourth		55.6		35.8		35.6		13.4		13.1		0.10

2013
First	$	26.9	$	0.2	$	0.2	$	—	$	—	$	—
Second		26.9		11.0		11.0		—		—		—
Third		20.2		22.4		22.4		—		—		—
Fourth		20.3		5.8		5.7		—		—		—

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

Management of the Company, with the participation of its Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the annual period. Our disclosure controls and procedures have been designed to provide reasonable assurance that the information required to be disclosed in the reports we file or submit under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, to allow timely decisions regarding required disclosures. Based on their evaluation, as of the end of the annual period covered by this Form 10-K, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended), were not effective because of the material weaknesses in our internal control over financial reporting described below.

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

We did not maintain effective internal control over the completeness and accuracy of revenues. Specifically, controls were not designed or effectively operating to review the completeness and accuracy of journal entries required to properly accrue revenues and record loss/gain from pipeline operations. This control deficiency did not result in any material adjustments to our consolidated financial statements for the year ended December 31, 2014 but resulted in the revision of our Predecessor’s unaudited financial statements for the three-month period ended March 31, 2013. This control deficiency could result in misstatements of the aforementioned accounts and related disclosures that would result in a material misstatement of the financial statements that would not be prevented or detected. Accordingly, our management has determined that this control deficiency constitutes a material weakness.

In addition, we did not maintain effective internal control over the accuracy of tariff rates and associated inputs which impacts the accuracy and reporting of revenues. Specifically, effective controls were not designed or effectively operating to review the accuracy of tariff rates and associated inputs. This control deficiency resulted in the restatement of our combined audited financial statements as of and for the year ended December 31, 2013 and the revision of our combined financial statements as of and for the period ended June 30, 2014 as described below.

On November 20, 2014, Shell Midstream Partners, L.P. concluded that the audited 2013 combined financial statements of its accounting predecessor, the Houston-to-Houma crude oil pipeline system (“Ho-Ho”), in which the Partnership owns a 43% interest, contained an error that resulted in a $2.8 million understatement of Ho-Ho’s total revenue and net income for 2013. As a result of this error, Ho-Ho’s net parent investment and total assets were understated by $1.9 million for the year ended December 31, 2013 and $1.0 million as of June 30, 2014, after giving effect to certain payments made on accounts receivable. There was no impact on Ho-Ho’s revenue, net income or total cash flow for the six months ended June 30, 2014. The error was the result of revenue attributable to Ho-Ho that was instead recorded by administrative error to an unrelated pipeline system owned by an affiliate of the Partnership. The error resulted from a manual data entry mistake as described below. Additionally, this control deficiency could result in misstatements of revenue, accounts receivable, allowance oil and net parent investment and related disclosures that would result in a material misstatement of the combined financial statements that would not be prevented or detected. 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 system, 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.

Despite the material weaknesses, we have concluded that the financial statements included in this report fairly present in all material respects our financial condition, results of operations and cash flows for the periods presented.

Internal control over financial reporting has inherent limitations. Internal control over financial reporting is a process that involves human diligence and compliance and is subject to lapses in judgment and breakdowns resulting from human failures. Internal control over financial reporting also can be circumvented by collusion or improper management override. Because of such limitations, there is a risk that material misstatements will not be prevented or detected on a timely basis by internal control over financial reporting.

However, these inherent limitations are known features of the financial reporting process. Therefore, it is possible to design into the process safeguards to reduce, though not eliminate, this risk.

Internal Control Over Financial Reporting and Changes in Internal Control Over Financial Reporting

The SEC, as required by Section 404 of the Sarbanes-Oxley Act, adopted rules that generally require every company that files reports with the SEC to include a management report on the company’s internal control over financial reporting in its annual report. This Annual Report on Form 10-K does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of our independent registered public accounting firm due to a transition period established by SEC rules applicable to new public companies. We are not required to comply with the auditor attestation requirement of Section 404 of the Sarbanes-Oxley Act while we qualify as an “emerging growth company” as defined in the Jumpstart Our Business Startups Act of 2012.

Other than the actions mentioned above, there have been no changes in our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Disclosures Required Pursuant to Section 13(r) of the Securities Exchange Act of 1934

In accordance with our General Business Principles and Code of Conduct, Shell seeks to comply with all applicable international trade laws including applicable sanctions and embargoes.

Under the Iran Threat Reduction and Syria Human Rights Act of 2012, and Section 13(r) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), we are required to include certain disclosures in our periodic reports if we or any of our “affiliates” (as defined in Rule 12b-2 under the Exchange Act) knowingly engaged in certain specified activities during the period covered by the report. Because the Securities and Exchange Commission (“SEC”) defines the term “affiliate” broadly, it includes any entity controlled by us as well as any person or entity that controls us or is under common control with us.

The disclosure below relates solely to activities conducted by non-U.S. affiliates of Royal Dutch Shell plc that may be deemed to be under common "control" with us. The disclosure does not relate to any activities conducted directly by us or our general partner, Shell Midstream Partners GP LLC (the “General Partner”) and does not involve our or the General Partner’s management.

For purposes of this disclosure, we refer to Royal Dutch Shell plc and its subsidiaries other than us, the General Partner and Shell Midstream LP Holdings LLC as the “RDS Group”. References to actions taken by the RDS Group mean actions taken by the applicable RDS Group company. None of the payments disclosed below were made in US dollars however, for disclosure purposes, all have been converted into US dollars at the appropriate exchange rate. We do not believe that any of the transactions or activities listed below violated US sanctions.

In 2010, the RDS Group ceased all of its upstream commercial activities and suspended new business development in Iran, as a direct consequence of the international sanctions imposed on the country.

In 2013, the RDS Group closed its small representative office in Iran. In 2014, the RDS Group paid $6,140 to the Iranian Ministry of Finance, consisting of a final settlement of corporate income tax related to the financial year ended December 31, 2007, an income tax penalty payment related to the financial year ended December 31, 2011, and stamp duties. These payments were made through checks guaranteed by Bank Karafarin, where the RDS Group maintains accounts. These transactions did not generate gross revenue or net profit. However, the RDS Group’s cash deposits in Bank Karafarin (balance of $3.1 million at December 31, 2014) generated non-taxable interest income of $0.5 million in 2014. In the future, the RDS Group expects to make additional payments as a result of theongoing liquidation process, including tax payments.

Payments to the Iranian Civil Aviation Authority for the clearance of overflight permits for RDS Group aircraft over Iranian airspace amounted to approximately $5,960 in 2014. There was no gross revenue or net profit associated with these transactions. On occasion, RDS Group aircraft may be routed over Iran and therefore these payments may continue in the future.

An amount of $202 was paid to the Consulate of Iran in the UK, relating to a British citizen, born in Iran, who was relocating with her RDS Group-employed spouse to the United Arab Emirates. The costs were for duplicates of birth certificates and other documents required to obtain a residence permit in the United Arab Emirates. This transaction generated no gross revenue or net profit, and is in accordance with the RDS Group’s expatriate policy.

In the downstream business, through the RDS Group subsidiary Deheza S.A.I.C.F.eI., the RDS Group provided retail services in August 2014 to the Iranian embassy in Argentina (Embajada de la República Islámica de Irán). This transaction generated gross revenue of $63 and an estimated net profit of $6. The RDS Group has no contractual agreement with this embassy.

At December 31, 2014, the RDS Group has approximately $2,164 million payable to, and $12 million receivable from, the National Iranian Oil Company. The payable amount decreased by $265 million during 2014 as a result of currency movements. There was no change in the principal amount. The RDS Group is unable to settle the payable position as a result of applicable sanctions.

We are managed by the board of directors and executive officers of Shell Midstream Partners GP LLC, our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election by our unitholders in the future. SPLC owns all of the membership interests in our general partner. Our general partner has a board of directors, and our common unitholders are not entitled to elect the directors or to participate directly or indirectly in our management or operations. Our general partner will be liable, as general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our general partner.

Our general partner currently has eight directors. SPLC appointed all members to the board of directors of our general partner. We have three directors who have been determined by our board of directors to be independent under the independence standards of the New York Stock Exchange (“NYSE”).

We do not have any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct operations, whether through directly hiring employees or by obtaining services of personnel employed by Shell, SPLC or third parties, but we sometimes refer to these individuals as our employees because they provide services directly to us.

Although most companies listed on the NYSE are required to have a majority of independent directors serving on the board of directors of the listed company, the NYSE does not require a publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner or to establish a compensation or a nominating and corporate governance committee. We are, however, required to have an audit committee of at least three members within one year of the date our common units are first listed on the NYSE, and all of our audit committee members are required to meet the independence and financial literacy tests established by the NYSE and the Exchange Act.

The board of directors of our general partner has an audit committee and a conflicts committee. The board of directors may also have such other committees as the board determines from time to time. Each of the standing committees of the board of directors has the composition and responsibilities described below.

Our general partner has an audit committee composed of at least three directors, each of whom meets the independence and experience standards established by the NYSE and the Exchange Act. Our audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. Our audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to our audit committee. Messrs. Jones, Bender and Fierro currently serve as members of our audit committee; Mr. Jones is the committee chair. Each of Messrs. Jones, Bender and Fierro is deemed to be “financially literate” as defined by the listing standards of NYSE, and each of Messrs. Jones and Fierro is deemed an “audit committee financial expert,” as defined in SEC regulations. Our audit committee charter is posted on the “Corporate Governance” section of our website.

In accordance with the terms of our partnership agreement, at least two members of the board of directors of our general partner will serve on our conflicts committee to review specific matters that may involve conflicts of interest. The members of our conflicts committee cannot be officers or employees of our general partner or directors, officers, or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. In addition, the members of our conflicts committee cannot own any interest in our general partner or its affiliates or any interest in us or our subsidiaries other than common units or awards, if any, under our incentive compensation plan. Messrs. Bender, Jones and Fierro currently serve as members of our conflicts committee; Mr. Bender is the committee chair.

Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors. The following table shows information for the directors and executive officers of our general.

Curtis R. Frasier. Curtis Frasier became a member of the Board of Directors of our general partner and is the Chairman of the Board of Directors in connection with the Offering. Employed at Shell from 1982 until 2013, Mr. Frasier provided legal advice and services in areas of commercial, corporate and international law based in the US, London and The Netherlands. Retired from Shell since September 2013, Mr. Frasier most recently served as Executive Vice President, Chief Legal Officer and General Counsel of Shell Upstream Americas as well as Head of Legal for Shell in the United States from 2009 to 2013. From 2006 to 2009, Mr. Frasier served as Executive Vice President, Shell Gas & Power—Americas where he led Shell’s Gas & Power businesses in the Americas, including natural gas pipelines, power plants and LNG re-gasification terminals. From 2002 to 2006, Mr. Frasier served as General Counsel of the global exploration and production business of Shell International Petroleum Company in The Hague. From 1997 to 2002, Mr. Frasier served as Executive Vice President, Shell US Gas & Power where he held executive leadership positions in Tejas Gas Corporation, Coral Energy (now Shell Gas Trading) and Shell US Gas & Power. Following the sale of Shell’s natural gas processing assets to Enterprise Products Partners, L.P., Mr. Frasier served as a member of the Board of Directors of Enterprise Products GP, LLC, the general partner of Enterprise from 1999 to 2002. From 1995 to 1997, Mr. Frasier served as President of Shell Midstream Enterprises, a producer services company providing third-party oil and natural gas processing, transportation and marketing. From 1994 to 1995, Mr. Frasier also served as Manager, Supply Operations, Shell Oil Company managing Shell’s crude oil and refined product logistics throughout the United States. Mr. Frasier is an Executive Board Member of the Institute for Energy Law; Member of the Board of Trustees, the Center for American and International Law; Member of the Board of Directors, the Julie Ann Wrigley Global Institute of Sustainability; and Member of the Board of Visitors, the University of Tulsa College of Law’s Sustainable Energy and Resource Law. Mr. Frasier earned a Bachelor of Arts from Arizona State University and a Juris Doctorate from the University of Tulsa. We believe that Mr. Frasier’s extensive experience in commercial and legal roles in the midstream industry and his prior experience as a director of the general partner of a master limited partnership makes him well qualified to serve as the Chairman of the Board of Directors of our general partner.

Margaret (Peggy) C. Montana. Peggy Montana was appointed Chief Executive Officer, President and a member of the Board of Directors of our general partner in May 2014. She devotes the majority of her time to her roles in Shell Downstream and also spends time, as needed, directly managing our business and affairs. Ms. Montana became Executive Vice President, US Pipelines & Special Projects – Americas in Shell Downstream Inc. in January 2014. Ms. Montana served as Executive Vice President, Supply & Distribution, from 2009 to 2014, where she was responsible for hydrocarbon supply to Shell’s downstream worldwide fuels manufacturing and marketing businesses. Prior to 2009, Ms. Montana served in the U.S. from 2004 as Vice President, Supply, and then Vice President, Global Distribution, where she led Shell’s fuels global terminaling and distribution activities. In these various roles, Ms. Montana has led Shell’s U.S. pipeline business since 2006. In 2001, Ms. Montana became General Manager, Distribution for Shell’s Asia Pacific business based in Singapore and served on the Board of Shell Pakistan Limited. Ms. Montana began her more than 37-year career at Shell as an engineer in Shell’s Deer Park Refinery. Ms. Montana holds a bachelor of science in Chemical Engineering from the University of Missouri, Rolla. Ms. Montana currently serves as the Chair of the American Petroleum Institute Downstream Committee and is a member of the Board of Directors of the Houston YMCA. We believe that Ms. Montana’s extensive experience in the energy industry, particularly her experience in supply and distribution and in the pipeline sector, makes her well qualified to serve as a member of the Board of Directors of our general partner.

Susan M. Ward. Susan Ward was appointed Vice President, Chief Financial Officer in May 2014, and became a member of the Board of Directors of our general partner in connection with the Offering. Ms. Ward has served as Head, M&A and Commercial Finance – Americas for Shell Oil Company since January 2010. Ms. Ward devotes the majority of her time to her role as Head, M&A

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

Alton (Greg) G. Smith. Greg Smith became Vice President, Operations of our general partner in connection with the Offering. Mr. Smith devotes the majority of his time to his roles at SPLC and also spends time, as needed, devoted to our business and affairs. Mr. Smith was appointed President, SPLC in November 2010. In January 2011, Mr. Smith also assumed the role of General Manager, Gulf of Mexico Operations. Prior to this appointment he served as the Gulf of Mexico Regional Operations Manager for SPLC, a role in which he had day-to-day operations accountability for Shell’s then 3,500 miles of crude oil, chemical and product pipelines located offshore Gulf of Mexico and along the Texas/Louisiana Gulf Coast. Mr. Smith started his career with SPLC in 1983 and has held a number of assignments of increasing responsibility within Shell, primarily in engineering and operations. These roles include Manager of Gulf of Mexico Business Development, Control Center Manager, and Manager of Distribution Operations Support and Engineering. He has served as the Chairman of the API Pipeline Committee and on the API Cybernetics Committee and the Performance Excellence Committee. Mr. Smith earned a Bachelor of Science in Electrical Engineering from The Ohio State University.

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

Kevin M. Nichols. Kevin Nichols became Vice President, Commercial of our general partner in connection with the Offering. Since June 2012, Mr. Nichols has served as Vice President and General Manager, Business Development for SPLC. Mr. Nichols devotes the majority of his time to his roles at SPLC and also spends time, as needed, devoted to our business and affairs. Mr. Nichols is currently responsible for commercial activities that include business development, oil movements, tariffs, joint venture governance, and portfolio activity. Mr. Nichols currently sits on the joint venture board of Colonial as Shell’s representative and he also serves on the SPLC Leadership Team. Since joining Shell in 1991, Mr. Nichols has held numerous role of increasing responsibility in Shell managing regions of Shell’s Retail business and from 2008 to 2012 worked in Shell’s Downstream Strategy group in London where he set strategy for market entries and growth in Asia. Mr. Nichols earned a Bachelor of Science in Management from San Diego State University and an MBA from Rice University.

Lori M. Muratta. Lori Muratta became Vice President, General Counsel and Secretary of our general partner in connection with the Offering. Ms. Muratta devotes the majority of her time to our business and affairs and also spends time devoted to the business and affairs of Shell. Prior to her current role, from 2000 Ms. Muratta served as Senior Counsel for Shell Oil Company, where she advised the company in mergers, acquisitions, divestments, joint ventures and financings in the upstream, midstream and downstream businesses. She also provided corporate law support to the Shell’s U.S. subsidiaries and affiliates. Before her time at Shell, Ms. Muratta was Attorney and Manager of Communications at Solvay America, Inc. and worked as an associate at Mayor, Day, Caldwell & Keeton LLP and O’Melveny & Myers LLP. Ms. Muratta received a Bachelor of Science in Foreign Service, cum laude, from Georgetown University and a Juris Doctor, cum laude, from Harvard Law School.

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

Paul R. A. Goodfellow. Paul Goodfellow became a member of the Board of Directors of our general partner in connection with the Offering. Since February 2015, Dr. Goodfellow has served as Vice President, United Kingdom and Ireland for Shell U.K. Limited. From January 2013 to February 2015, Dr. Goodfellow served as the Vice President Unconventionals US and Canada for Shell Upstream Americas. Prior to this role, Dr. Goodfellow moved into the role of Vice President Development, Onshore in September 2009 for Shell Upstream Americas responsible for field development planning, technical and technology functions. In July 2008, Dr. Goodfellow was named Venture Manager for North America Onshore. Since 2007, he has also served on the board of directors of Shell’s Bully deepwater drillship joint venture. In August of 2003 he took up the role of Wells Manager for the Americas Region and in 2000, Dr. Goodfellow was assigned to Shell Exploration & Production Company as the Operations Manager for Deepwater Drilling and Completions. He has worked in a variety of wells related roles throughout the Shell Group. Dr. Goodfellow worked in the mining industry in South Africa and Finland prior to joining Shell in Holland in 1991. Dr. Goodfellow is a Chartered Engineer and a member of the Institute of Mining and Metallurgy and SPE. Dr. Goodfellow earned a Bachelor of Engineering in Mining Engineering and a Ph.D. in Rock Mechanics from The Camborne School of Mines in the United Kingdom. Dr. Goodfellow serves on the board of the Center for Sustainable Shale Development. We believe that Dr. Goodfellow’s extensive experience in the energy industry makes him well qualified to serve as a member of the Board of Directors of our general partner.

Rob L. Jones. Rob Jones became a member of the Board of Directors of our general partner in connection with the Offering. Mr. Jones is a private investor and consultant based in Houston, Texas. From September 2012 until June 2014, Mr. Jones served as an Executive in Residence at the McCombs School of Business at the University of Texas at Austin (McCombs). Mr. Jones continues as a guest lecturer and speaker at McCombs. Mr. Jones also served as Lead Independent Director for Susser Petroleum Partners, L.P. (SUSP), a publicly traded partnership. From 2007 through June 2012, Mr. Jones was the Co-Head of Bank of America Merrill Lynch Commodities (MLC). MLC is a global commodities trading business and a wholly-owned subsidiary of Bank of America Merrill Lynch. Prior to taking leadership of MLC in 2007, he served as Head of Merrill Lynch’s Global Energy and Power Investment Banking Group and founder of Merrill Lynch Commodities Partners, a private equity vehicle for the firm. An investment banker with Merrill Lynch and The First Boston Corporation for over 20 years, Mr. Jones worked extensively with a variety of energy and power clients, with a particular focus on the natural gas and utility sectors. From 1980 until 1985, Mr. Jones was a Financial Associate with the oil and gas exploration and production division of Sun Company, primarily based in Dallas, Texas. He is a graduate of the University of Texas, where he received a Bachelor of Business Administration in Finance with Honors and an MBA with High Honors and was a Sord Scholar. Mr. Jones is a Life Member of the Dean’s Advisory Council of McCombs and an Emeritus Member of the Children’s Fund of Houston Texas. We believe that Mr. Jones’ extensive experience in financial and mergers and acquisitions roles in the energy banking industry and his experience as a lead independent director makes him well qualified to serve as a member of the Board of Directors of our general partner.

James (Jim) J. Bender. Jim Bender became a member of the Board of Directors of our general partner in connection with the Offering. From May 2014 to July 2014, Mr. Bender served as Senior Vice President of Special Projects of WPX Energy, Inc. (WPX), and from December 2013 to May 2014 as interim President and Chief Executive Officer of WPX. Mr. Bender also served as a member of the board of directors of WPX from December 2013 to May 2014. He also served as Chairman of the Board of Directors of APCO Oil and Gas International, Inc. (a publicly-traded affiliate of WPX) from December 2013 to August 2014. From April 2011 to December 2013, Mr. Bender served as Senior Vice President and General Counsel of WPX. Mr. Bender has served as a member of the board of directors of Two Harbors Investment Corp. since May 2013. Mr. Bender served as Senior Vice President and General Counsel of The Williams Companies, Inc. (Williams) from December 2002 to December 2011 and General Counsel of Williams Partners GP LLC, the general partner of Williams Partners L.P., from September 2005 until December 2011. Mr. Bender served as the General Counsel of the general partner of Williams Pipeline Partners L.P., from 2007 until its merger with Williams Partners L.P. in August 2010. From June 1997 to June 2002, he was Senior Vice President and General Counsel of NRG Energy, Inc. We believe that

Mr. Bender’s extensive experience in the energy industry, and more specifically with sponsored master limited partnerships, makes him well qualified to serve as a member of the Board of Directors of our general partner.

Carlos A. Fierro. Carlos Fierro became a member of the Board of Directors of our general partner on January 1, 2015. Mr. Fierro is a private investor based in Washington, D.C. In addition to this board of directors, Mr. Fierro serves on the Board of Directors of Sendero Midstream Partners, a portfolio company of Energy Capital Partners, and on the Board of Directors and Audit Committee of Athabasca Oil Company, a Canadian energy company with a focused strategy on the development of thermal and light oil assets. From September 2008 through June 2013, Mr. Fierro was a Managing Director and Global Head of the Natural Resources Group of Barclays, which encompasses Barclays’ oil and gas, chemicals and metals and mining businesses. Mr. Fierro joined Barclays Capital in 2008 from Lehman Brothers, where he was the Global Head of the Natural Resources Group from January 2007 through September 2008. From September 2004 through January 2007, Mr. Fierro served as Co-Head of Mergers & Acquisitions in Europe for Lehman Brothers from a base in London. Prior to that, Mr. Fierro led Lehman Brothers' mergers and acquisitions effort in the natural resources sector for seven years, based in New York. Throughout his banking career, Mr. Fierro participated in the development, structuring, negotiation and execution of numerous merger, acquisition, divestiture, restructuring and joint venture transactions. In the natural resources sector, these included transactions for companies involved in exploration and production, refining and marketing, oil field services, mining, pipelines, petrochemicals and coal. Prior to his banking career, Mr. Fierro practiced corporate, M&A and securities law for eleven years with Baker & Botts, L.L.P., where he was a partner. In his practice, Mr. Fierro devoted his time principally to oil and gas transactions, including hostile takeovers, acquisitions, divestitures, public and private debt and equity financing transactions, corporate restructurings and proxy fights. Mr. Fierro holds a B.A. from the University of Notre Dame and a J.D. from Harvard University. We believe that Mr. Fierro’s extensive experience in the energy banking industry, and his work in mergers and acquisitions, makes him well qualified to serve as a member of the Board of Directors of our general partner.

Although the chief executive officer of our general partner currently does not also serve as the chairman of the board, the board of directors of our general partner has no policy with respect to the separation of the offices of chairman of the board of directors and chief executive officer. Instead, that relationship is defined and governed by the amended and restated limited liability company agreement of our general partner, which permits the same person to hold both offices. Directors of the board of directors of our general partner are designated or elected by SPLC. Accordingly, unlike holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement.

Our corporate governance guidelines will provide that the board of directors of our general partner is responsible for reviewing the process for assessing the major risks facing us and the options for their mitigation. This responsibility will be largely satisfied by our audit committee, which is responsible for reviewing and discussing with management and our independent registered public accounting firm our major risk exposures and the policies management has implemented to monitor such exposures, including our financial risk exposures and risk management policies.

The listing rules of the NYSE do not require us to maintain, and we do not maintain, a compensation committee.

We have adopted a Code of Conduct applicable to all employees, directors and officers, as well as a Code of Ethics applicable to our general partner’s chief financial officer. Our Code of Conduct covers topics including, but not limited to, conflicts of interest, insider dealing, competition, discrimination and harassment, confidentiality, bribery and corruption, sanctions and compliance procedures. Our Code of Ethics covers topics including, but not limited to, conflicts of interest, gifts and disclosure controls. Our Code of Conduct and Code of Ethics are posted on the “Corporate Governance” section of our website.

We and our general partner were formed in March 2014 and did not accrue any obligation with respect to compensation for directors and officers for the 2013 fiscal year or for any prior periods. Neither we nor our general partner employ any of the individuals who serve as executive officers of our general partner and are responsible for managing our business. Our general partner does not have a compensation committee. We are managed by our general partner, the executive officers of which are employees of Shell. We and our General Partner have entered into an omnibus agreement with SPLC pursuant to which, among other matters:

These officers and all other personnel necessary for our business to function are employed and compensated by Shell, subject to the administrative services fee in accordance with the terms of the omnibus agreement. Under the omnibus agreement, none of Shell’s long-term incentive compensation expense is allocated directly to us. We are responsible for paying the long-term incentive compensation expense, if any, associated with our long-term incentive plan described below. The executive officers of our general partner continue to participate in employee benefit plans and arrangements sponsored by Shell, including plans that may be established in the future. Our general partner has not entered into any employment agreements with any of its executive officers. We did not grant any awards under our long-term incentive plan to our officers or directors, nor do we have a current intent to do so. Our long-term incentive plan is described below under “—Long-Term Incentive Plan”.

Responsibility and authority for compensation-related decisions for executive officers of our general partner reside with Shell’s human resources function and the RDS Management Development Committee, as applicable. Other than compensation under our long-term incentive plan, which requires action by the Board of Directors of our general partner, any such compensation decisions are not subject to any approvals by the Board of Directors of our general partner or any committees thereof. Our “Named Executive Officers” (NEOs) consist of our general partner’s principal executive officer, principal financial officer and the most highly compensated executive officer other than its principal executive officer and principal financial officer as of December 31, 2014, being:

Each of Ms. Montana, Ms. Ward, and Ms. Muratta devote a portion of their time to their roles in Shell and spend time, as needed, directly managing our business and affairs. Pursuant to the terms of the omnibus agreement, we pay a fixed administrative fee to SPLC, which covers, among other things, the services provided to us by our NEOs. None of Ms. Montana, Ms. Ward, or Ms. Muratta receive any separate amounts of compensation for their services to our business or as executive officers of our General Partner and, except for the fixed administrative fee we pay SPLC, we do not otherwise pay or reimburse any compensation amounts to or for them.

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

Name and Principal Position	Year	Salary		Stock Awards		Bonus		Stock Options		Non-Equity Incentive Compensation Plan		Change in Pension Value and Nonqualified Deferred Compensation Earnings		All Other Compensation		Total
Margaret C. Montana, President and Chief Executive Officer⁽¹⁾	2014		—		—		—		—		—		—		—		—
Susan M. Ward, Vice President and Chief Financial Officer⁽¹⁾	2014		—		—		—		—		—		—		—		—
Lori M. Muratta, Vice President, General Counsel and Secretary⁽¹⁾	2014		—		—		—		—		—		—		—		—

Narrative Disclosure to Summary Compensation Table and Additional Narrative Disclosure

Shell provides compensation to its executives in the form of base salaries, annual cash incentive awards, long-term equity incentive awards and participation in various employee benefit plans and arrangements, including broad based and supplemental defined contribution and defined benefit retirement plans. In addition, although our NEOs have not entered into employment agreements with Shell, Ms. Montana and Ms. Ward have end of employment arrangements with Shell under which they would receive separation payments and benefits from Shell based on termination at the employer’s initiative or on mutually agreed terms. In the future, Shell may provide different or additional compensation components, benefits, or perquisites to our NEOs.

The following sets forth a more detailed explanation of the elements of Shell’s executive compensation program.

Our named executive officers earn a base salary for their services to Shell and its affiliates, which amounts are paid by Shell or its affiliates other than us. We incur only a fixed expense per month under the omnibus agreement with respect to the compensation paid by Shell to each of our NEOs.

Our NEOs are eligible to earn cash payments from Shell under Shell’s annual incentive bonus program and other discretionary bonuses that may be awarded by Shell. Any bonus payments earned by the NEOs will be paid by Shell and will be determined solely by Shell without input from us or our general partner or its board of directors. The amount of any bonus payment made by Shell will not result in changes to the contractually fixed fee for executive management services that we pay to Shell under the omnibus agreement.

Shell maintains a long term incentive program pursuant to which it grants equity based awards in Royal Dutch Shell plc to certain of its executives and employees. Our NEOs may receive awards under Shell’s equity incentive plan from time to time as may be determined by the RDS Management Development Committee. The amount of any long term incentive compensation made by Shell will not result in changes to the contractually fixed fee for executive management services that we will pay to Shell under the omnibus agreement.

Our NEOs are eligible to participate in the employee benefit plans and programs that Shell offers to its employees, subject to the terms and eligibility requirements of those plans. Our NEOs are also eligible to participate in Shell’s tax-qualified defined contribution and defined benefit retirement plans to the same extent as all other Shell employees. Shell also has certain supplemental retirement plans in which its executives and key employees participate.

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

Officers or employees of Shell or its affiliates who also serve as directors of our general partner do not receive additional compensation for such service. Our general partner’s directors who are not also officers or employees of Shell receive compensation for service on the Board of Directors and its committees. We currently pay such directors $150,000. We currently pay the audit

committee chairman an additional $15,000 and the conflicts committee chairman an additional $15,000. In addition, each such director will be reimbursed for out-of-pocket expenses in connection with attending meetings of the board and committee meetings. We currently pay meeting fees to such directors in the amount of $2,000 for each in-person board meeting, $2,000 for each in-person committee meeting, $1,000 for each telephonic board meeting and $1,000 for each telephonic committee meeting. Each director will be fully indemnified by us for actions associated with being a director to the fullest extent permitted under Delaware law pursuant to our partnership agreement.

The following summarizes the compensation for our non-employee directors for 2014.

Name	Fees Earned or Paid in Cash		Unit Awards		Option Awards		Non-Equity Incentive Plan Compensation		Non-Qualified Compensation		Deferred Earnings		All Other Compensation		Total
Curtis R. Frasier	$	27,000	$	—	$	—	$	—	$	—	$	—	$	—	$	27,000
Rob L. Jones		33,500		—		—		—		—		—		—		33,500
James J. Bender		28,000		—		—		—		—		—		—		28,000
Carlos A. Fierro⁽¹⁾		—		—		—		—		—		—		—		—

(1) Because he became a director of our general partner on January 1, 2015, Mr. Fierro received no compensation from us in 2014.

Our general partner has adopted the Shell Midstream Partners, L.P. 2014 Incentive Compensation Plan (“LTIP”) for officers, directors and employees of our general partner or its affiliates, and any consultants, affiliates of our general partner or other individuals who perform services for us. Our general partner may issue our executive officers and other service providers long-term equity based awards under the plan, which awards would compensate the recipients thereof based on the performance of our common units and their continued employment during the vesting period, as well as align their long-term interests with those of our unit holders. Our general partner has not issued, and does not currently intend to issue any awards under the plan.

We are responsible for the cost of awards granted under our LTIP and all determinations with respect to awards, if any, to be made under our LTIP will be made by the board of directors of our general partner or any committee thereof that may be established for such purpose or by any delegate of the board of directors or such committee, subject to applicable law, which we refer to as the plan administrator. We currently expect that the board of directors of our general partner or a committee thereof will be designated as the plan administrator. The following description reflects the principal terms that are currently expected to be included in the LTIP.

The LTIP permits the board of directors of our general partner or any applicable committee or delegate thereof, in its discretion, subject to applicable law, from time to time to grant unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. The purpose of awards, if any, under the LTIP is to provide additional incentive compensation to individuals providing services to us, and to align the economic interests of such individuals with the interests of our unitholders. The LTIP limits the number of units that may be delivered pursuant to vested awards to 6,000,000 common units, subject to proportionate adjustment in the event of unit splits and similar events. Common units subject to awards that are canceled, forfeited, or otherwise terminated without delivery of the common units are generally available for delivery pursuant to other awards, as provided in the LTIP.

A restricted unit is a common unit that is subject to forfeiture. Upon vesting, the forfeiture restrictions lapse and the recipient holds a common unit that is not subject to forfeiture. A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or, on a deferred basis, upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. The administrator of the LTIP may make grants of restricted and phantom units under the LTIP that contain such terms, consistent with the LTIP, as the administrator may determine are appropriate, including the period over which restricted or phantom units will vest. The administrator of the LTIP may, in its discretion, base vesting on the grantee’s completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the LTIP) or as otherwise described in an award agreement.

Distributions made by us with respect to awards of restricted units may be subject to the same vesting requirements as the restricted units.

The administrator of the LTIP, in its discretion, may also grant distribution equivalent rights, either as standalone awards or in tandem with other awards. Distribution equivalent rights are rights to receive an amount in cash, restricted units or phantom units equal to all or a portion of the cash distributions made on units during the period an award remains outstanding.

The LTIP may also permit the grant of options covering common units. Unit options represent the right to purchase a number of common units at a specified exercise price. Unit appreciation rights represent the right to receive the appreciation in the value of a number of common units over a specified exercise price, either in cash or in common units. Unit options and unit appreciation rights may be granted to such eligible individuals and with such terms as the administrator of the LTIP may determine, consistent with the LTIP; however, a unit option or unit appreciation right must have an exercise price equal to at least the fair market value of a common unit on the date of grant.

Awards covering common units may be granted under the LTIP with such terms and conditions, including restrictions on transferability, as the administrator of the LTIP may establish.

Awards may consist of profits interest units to the extent contemplated by our partnership agreement. The administrator will determine the applicable vesting dates, conditions to vesting and restrictions on transferability and any other restrictions for profits interest awards.

The LTIP may also permit the grant of “other unit-based awards,” which are awards that, in whole or in part, are valued or based on or related to the value of a common unit. The vesting of any other unit-based award may be based on a grantee’s continued service, the achievement of performance criteria or other measures. On vesting or on a deferred basis upon specified future dates or events, any other unit-based award may be paid in cash and/or in units (including restricted units), or any combination thereof as the administrator of the LTIP may determine.

Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our general partner in the open market, common units already owned by our general partner or us, common units acquired by our general partner directly from us, or any other person or any combination of the foregoing.

If an “equity restructuring” event occurs that could result in an additional compensation expense under applicable accounting standards if adjustments to awards under the LTIP with respect to such event were discretionary, the administrator of the LTIP will equitably adjust the number and type of units covered by each outstanding award and the terms and conditions of such award to equitably reflect the restructuring event, and the administrator will adjust the number and type of units with respect to which future awards may be granted under the LTIP. With respect to other similar events, including, for example, a combination or exchange of units, a merger or consolidation or an extraordinary distribution of our assets to unitholders, that would not result in an accounting charge if adjustment to awards were discretionary, the administrator of the LTIP has the discretion to adjust awards in the manner it deems appropriate and to make equitable adjustments, if any, with respect to the number and kind of units subject to outstanding awards, the terms and conditions of any outstanding awards and the grant or exercise price per unit for outstanding awards under the LTIP. Furthermore, in connection with a change in control of us or our general partner, or a change in any law or regulation affecting the LTIP or outstanding awards or any relevant change in accounting principles, the administrator of the LTIP will generally have discretion to (i) accelerate the time of exercisability or vesting or payment of an award, (ii) permit awards to be surrendered in exchange for a cash payment, (iii) cause awards then outstanding to be assumed or substituted for other rights by the surviving entity in the change in control, (iv) provide for either (A) the termination of any award in exchange for a payment of the amount that would have been received upon the exercise of such award or realization of the grantee’s rights under such award or (B) the replacement of an award with other rights or property selected by the administrator having an aggregate value not exceeding the amount that could have been received upon the exercise of such award or realization of the grantee’s rights had such award been currently exercisable or payable or fully vested, (v) provide that an award be assumed by the successor or survivor entity, or be exchanged for similar options,

rights or awards covering the equity of the successor or survivor, with appropriate adjustments thereto, (vi) make adjustments in the number and type of units subject to outstanding awards, the number and kind of outstanding awards, the terms and conditions of, and/or the vesting and performance criteria included in, outstanding awards, (vii) provide that an award will vest or become exercisable or payable and/or (viii) provide that an award cannot be exercised or become payable after such event and will terminate upon such event.

The LTIP provides the administrator with the discretion to determine in each award agreement the effect of a termination of a grantee’s employment, membership on our general partner’s board of directors or other service arrangement on the grantee’s outstanding awards.

The administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The LTIP automatically terminates on the tenth anniversary of the date it was initially adopted by our general partner. The administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially impair the vested rights of the participant without the consent of the affected participant or result in taxation to the participant under Section 409A of the Internal Revenue Code.

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

The following table sets forth information about Shell Midstream Partners, L.P. common units that may be issued under all existing equity compensation plans as of December 31, 2014.

The following table sets forth the beneficial ownership of common units of Shell Midstream Partners, L.P. held by beneficial owners of 5% or more of the common units, by each director, director nominee and named executive officer of our general partner and by the directors, director nominee and executive officers of our general partner as a group. The percentage of units beneficially owned is based on 67,475,068 common units and 67,475,068 subordinated units being outstanding.

Name of Beneficial Owner⁽¹⁾	Common Units Beneficially Owned		Percentage of Common Units Beneficially Owned			Subordinated Units to be Beneficially Owned		Percentage of Subordinated Units to be Beneficially Owned			Percentage of Total Common and Subordinated Units to be Beneficially Owned
Shell Pipeline Company LP⁽²⁾		21,475,068		31.8	%		67,475,068		100	%		65.9	%
OppenheimerFunds, Inc., Two World Financial Center, 225 Liberty St., New York, NY 10281⁽³⁾		5,573,741		8.3	%		—		—			4.1	%
Tortoise Capital Advisors, L.L.C. 11550 Ash Street, Suite 300, Leawood, Kansas 66211⁽⁴⁾		4,567,322		6.8	%		—		—			3.4	%
Chickasaw Capital Management, LLC, 6075 Poplar Ave. Suite 402, Memphis, TN 38119⁽⁵⁾		4,465,475		6.6	%		—		—			3.3	%
Curtis R. Frasier		—		—			—		—			—
Margaret C. Montana		6,000		0.0	%		—		—			0.0	%
Susan M. Ward		25,000		0.0	%		—		—			0.0	%
Alton G. Smith		1,565		0.0	%		—		—			0.0	%
Michele F. Joy		1,490		0.0	%		—		—			0.0	%
Kevin M. Nichols		8,500		0.0	%		—		—			0.0	%
Lori M. Muratta		2,000		0.0	%		—		—			0.0	%
Gerard B. Paulides		—		—			—		—			—
Paul R. A. Goodfellow		—		—			—		—			—
Rob L. Jones		10,000		0.0	%		—		—			0.0	%
Carlos A. Fierro		3,000		0.0	%		—		—			0.0	%
James J. Bender		25,000		0.0	%		—		—			0.0	%
Directors and executive officers as a group (12 persons)		82,555		0.1	%		—		—			0.1	%

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

As of March 24, 2015 the general partner and its affiliates owned 21,475,068 common units and 67,475,068 subordinated units, representing a 64.6% limited partner interest in us, and all of our incentive distribution rights. In addition, our general partner owned 2,754,084 general partner units representing a 2% general partner interest in us. Please read Part III, Item 10. “Directors, Executive Officers and Corporate Governance – Management of Shell Midstream Partners, L.P.” for additional information regarding director independence.

The following table summarizes the distributions and payments to be made by us to our general partner and its affiliates in connection with our ongoing operation and upon liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm’s-length negotiations.

In connection with the Offering we entered into an omnibus agreement with SPLC and our general partner that addressed the following matters:

So long as SPLC controls our general partner, the omnibus agreement will remain in full force and effect. If SPLC ceases to control our general partner, either party may terminate the omnibus agreement, provided that the indemnification obligations will remain in full force and effect in accordance with their terms.

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

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

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

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

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

Environmental Indemnification by SPLC. Under the omnibus agreement, SPLC will indemnify us for all violations of environmental laws and all environmental remediation or corrective action that is required by environmental laws, in each case to the extent (i) related to the ownership or operatorship assets contributed to us by SPLC and (ii) not identified in a voluntary audit or investigation undertaken outside the ordinary course of business by us. SPLC will also indemnify us for certain known and scheduled environmental matters related to our assets (“Scheduled Environmental Matters”). Except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us for any environmental losses unless SPLC is notified of such losses prior to the third anniversary of the closing of the offering. Furthermore, except for Scheduled Environmental Matters, SPLC will not be obligated to indemnify us until our aggregate indemnifiable losses in any year exceed a $0.5 million deductible (and then SPLC will only be obligated to indemnify us for amounts in excess of such deductible). SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million.

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

SPLC’s indemnity obligation for all environmental, title and litigation claims is capped at $15 million. SPLC’s indemnity obligation for tax liabilities and liabilities associated with SPLC’s retained assets is not subject to a cap.

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

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

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

General. SPLC contributed and Zydeco issued to us interests in Zydeco collectively representing an aggregate 43.0% ownership interest in Zydeco. SPLC owns the remaining 57.0% membership interest in Zydeco. Pursuant to a voting agreement that we executed with SPLC, we control cash distributions by Zydeco.

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

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

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

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

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

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

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

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

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

The partnership committee is required to meet no less often than annually, with the time and location of such meetings to be as the partnership committee determines. Special meetings of the partnership committee may be called by the chairman of the partnership committee or by the chairman or secretary of the partnership committee upon request of the partnership committee. The presence in person, or by conference telephone call, of members of the partnership committee representing at least two partners and 51% of the ownership interests constitutes a quorum of the partnership committee.

Except as noted below, all decisions of the partnership committee require the vote of at least 51% of the ownership interests in the partnership. Through our voting agreement with SPLC, we will be able to vote a majority of the ownership interests.

The following actions require the vote of members representing 100% of the ownership interests:

If the partnership is composed of only two partners, the following actions require the vote of members representing 100% of the ownership interests; if the partnership is composed of more than two partners, these actions only require the vote of a majority of the ownership interests. We entered into an amendment to the Mars partnership agreement that provides that, for purposes of the voting provisions under the Mars partnership agreement, we and SPLC together constitute one partner. As a result, the following actions require the approval of the unaffiliated third party:

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

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

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

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

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

determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Zydeco.

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

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

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

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

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

The affirmative vote of 80% of the voting power of all managers eligible to vote on the matter is required to adopt a matter. A manager is not eligible to vote on a matter due to a conflict of interest when (i) the matter concerns the level of tariffs or other charges of Bengal to be paid by shippers on the pipeline system or Bengal’s tariff policies and (ii) the manager’s appointing member or such member’s affiliate owns an ownership interest in any shipper on the pipeline system greater than its ownership interest in Bengal. Any action of the board may be taken by written consent of all of the managers entitled to vote on the action.

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

The members are required to meet with such frequency as the members may approve. The location of such meetings is Bengal’s principal office or such other place as shall be specified, along with the agenda, in the written notice of such meetings. Special meetings of the members may be called at such times as any member determines to be necessary. The presence in person, by telephone or by proxy of all of the members constitutes a quorum for the transaction of business at any meeting of the members. Each member is entitled to cast votes equal to the product of one hundred and the member’s current ownership interest on each matter voted upon by the board. Except as noted above, the affirmative vote of 80% of the voting power of all members is required to adopt a matter. Any action of the members may be taken by written consent of all of the members entitled to vote on the action.

Quarterly Cash Distributions. Bengal is required by the terms of its limited liability company agreement to make quarterly cash distributions to the members equal to 100% of Bengal’s “available cash,” which is defined to include the unrestricted cash and cash equivalents of Bengal less reasonable cash reserves, including those necessary for working capital and obligations or other contingencies of Bengal, as the board determines is proper to set aside in the best interests of Bengal. The board managers appointed by Colonial and us must jointly make the determinations related to Bengal’s establishment of cash reserves. Distributions are required to be made simultaneously to all members in proportion to their ownership interests within 30 days following the end of each quarter.

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

Transfer Restrictions. Under the Bengal limited liability company agreement, each member’s interest is subject to transfer restrictions, including a right of first refusal in favor of the other members. The right of first refusal does not apply in the case of transfers to an affiliate if the membership interest being transferred constitutes no more than 50% of the fair market value of such affiliate’s assets. In addition, if a member proposes to dispose of an interest, then the other members must provide consent and the board of managers must approve certain documents related to such transfer. Under the voting agreement between SPLC and us, SPLC will agree not to transfer any portion of its ownership interest in Bengal unless, among other conditions, after giving effect to the proposed transfer, (i) we would continue to have sufficient voting power such that any cash reserves by Bengal that would reduce the amount of cash distributed require our approval and (ii) we would be deemed to control Bengal for purposes of the Investment Company Act of 1940. We will determine whether these conditions are satisfied. Subject to these conditions, SPLC may transfer its retained ownership interest in Bengal.

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

General. SPLC contributed to us 10% of its 16.12% ownership interest in Colonial, as a result of which we own a 1.612% interest in Colonial and SPLC owns a 14.508% interest in Colonial. The remaining interests in Colonial are owned by third parties.

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

Governance. Colonial is managed by a five person board of directors. Each shareholder is required to vote its shares such that at all times one person, but not more than one person, nominated by each shareholder will be a member of the board of directors, provided that no such shareholder is required to vote its shares in favor of the nominee of a shareholder which either (i) has disposed of 80% or more of the shares which it held as of the date upon which it became a party to the shareholder agreement or (ii) owns less than 2.5% of the total outstanding stock of Colonial at the time of such vote.

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

Certain actions also require approval by shareholders. The vote of a majority of the stock issued, outstanding and entitled to vote is required to amend Colonial’s articles of incorporation. The following actions require the vote of 75% of the stock issued, outstanding and entitled to vote:

Amendments of certain sections of Colonial’s articles of incorporation require the vote of 80% of the stock issued, outstanding and entitled to vote, while amendments of other sections require the vote of 100% of the stock issued, outstanding and entitled to vote. Other than the actions which require unanimous approval by the shareholders, SPLC and the other shareholders of Colonial will be able to collectively make all decisions with respect to the operation of Colonial without our approval.

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

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

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

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

On October 31, 2014, in connection with the Offering, we entered into a $300.0 million credit facility with Shell Treasury Centre (West) Inc. as lender, which is an affiliate of the Shell. The credit facility will mature on the fifth anniversary of the closing date of the agreement. Borrowings under the credit facility will be generally available for working capital purposes. Our obligations under the credit facility rank at least pari passu with the claims of all our other unsecured and unsubordinated creditors, except for obligations mandatorily preferred by law applying to companies generally. Borrowings under the credit facility will bear interest, which will be calculated based on the three months LIBOR as of the quotation day relating to the interest period. This facility also includes customary fees, including an issuance fee, commitment fees, utilization fees and other fees. The credit agreement contains events of default customary for credit facilities of this nature, including, but not limited to, the failure to pay any principal, interest or fees when due, failure to satisfy any covenant, untrue representations or warranties, events of default under any other loan document under the new credit facility, default under any other material debt agreements, our insolvency, involvement in certain insolvency proceedings, initiation of certain creditors’ processes, unlawfulness and invalidity of the credit agreement and our repudiation of the agreement.

Upon the occurrence and during the continuation of an event of default under the credit agreement, the lenders may, among other things, accelerate and declare the outstanding loans to be immediately due and payable and exercise remedies against us as may be available to the lenders under the credit agreement and other loan documents. We have not incurred any borrowings under the credit agreement.

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

Zydeco has entered into a tax sharing agreement with an affiliate of Shell pursuant to which Zydeco has agreed to reimburse Shell for state and local income and franchise taxes attributable to Zydeco’s activity that is reported on Shell’s state or local income or franchise tax returns filed on a combined or unitary basis. Reimbursements under the agreement equal the amount of tax that Zydeco would be required to pay if it were to file a consolidated, combined or unitary tax return separate from Shell. Shell will compute and invoice Zydeco for the reimbursement amount within 90 days of Shell filing the combined or unitary tax return on which Zydeco’s activity is included. Zydeco may be required to make prepayments toward the reimbursement amount to the extent that Shell is required to make estimated tax payments. No payments were made in 2014.

SPLC is party to a pipeline operating agreement with Mars. Under the terms of the pipeline operating agreement, SPLC, on behalf of Mars, pays for the operation, maintenance, upkeep and repair of the pipeline facilities and Mars reimburses SPLC for all costs and expenses incurred in connection with providing services under the agreement. The agreement renews automatically from year to year unless either SPLC or Mars terminates the agreement prior to the end of the calendar year. Mars paid $12.0 million in 2014 for services rendered under this agreement.

SPLC is party to a pipeline operating agreement with Bengal. Under the terms of the pipeline operating agreement, Bengal pays for operating and support services for the operation, maintenance, and repair of the pipeline facilities. Bengal also reimburses SPLC for certain direct expenses incurred in connection with providing services under the agreement. The agreement was renewed in 2012 for a three-year period and expires on December 31, 2015. Bengal paid $9.6 million in 2014 for services rendered under this agreement.

Procedures for Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted policies for the review, approval and ratification of transactions with related persons. For the purposes of the policy, a “related person” is expected to be any director or executive officer of our general partner, any unitholder known to us to be the beneficial owner of more than 5% of the our common units, and any immediate family member of any such person, and a “related person transaction” is expected to be generally a transaction in which we are, or our general partner or any of our subsidiaries is, a participant, the amount involved exceeds $0.1 million, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the partnership agreement are not required to be reviewed or approved under the policy.

The policy sets forth certain categories of transactions that are deemed to be pre-approved by the audit committee of the board of directors of our general partner under the policy. After applying these categorical standards and weighing all of the facts and circumstances, the audit committee of the board of directors of our general partner must then either approve or reject the transaction in accordance with the terms of the policy.

The board of directors of our general partner has adopted a written policy, under which a director would be expected to bring to the attention of the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors of our general partner, be determined by a majority of the disinterested directors.

The following table presents fees for the year ended December 31, 2014, for professional services performed by our independent registered public accounting firm, PricewaterhouseCoopers LLP (PwC).

The Audit Committee has adopted a pre-approval policy that provides guidelines for the audit, audit-related, tax and other non-audit services that may be provided by PwC to the Partnership. All of the fees in the table above were approved in accordance with this policy. The policy (a) identifies the guiding principles that must be considered by the Audit Committee in approving services to ensure that PwC’s independence is not impaired; (b) describes the audit, audit-related, tax and other services that may be provided and the non-audit services that are prohibited; and (c) sets forth pre-approval requirements for all permitted services. Under the policy, all services to be provided by PwC must be pre-approved by the Audit Committee. The Audit Committee has delegated authority to approve permitted services to the Audit Committee’s Chair. Such approval must be reported to the entire Audit Committee at the next scheduled Audit Committee meeting.

The financial statements and supplementary information listed in the Index to Financial Statements, which appears in Part II, Item 8, are filed as part of this Annual Report.

Financial statement schedules are omitted because they are not required, not significant, not applicable or the information is shown in another schedule, the financial statements or the notes to consolidated financial statements.

The exhibits listed in the Index to Exhibits are filed as part of this Annual Report.

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit Number	Filing Date	SEC File No.
3.1	Amended and Restated Certificate of Limited Partnership of Shell Midstream Partners, L.P.	S-1	3.1	06/18/2014	333-196850
3.2	First Amended and Restated Agreement of Limited Partnership of Shell Midstream Partners, L.P. , dated as of November 3, 2014	8-K	3.1	11/03/2014	001-36710
3.3	Amended and Restated Certificate of Formation of Shell Midstream Partners GP LLC	S-1	3.3	06/18/2014	333-196850
3.4	First Amended and Restated Limited Liability Company Agreement of Shell Midstream Partners GP LLC, dated as of November 3, 2014	8-K	3.2	11/03/2014	001-36710
10.1	Contribution, Assignment and Assumption Agreement dated November 3, 2014 by and among Shell Pipeline Company LP, Shell Midstream Partners GP LLC, Shell Midstream Partners, L.P., Shell Midstream LP Holdings LLC, Shell Midstream Operating LLC, and Zydeco Pipeline Company LLC	8-K	10.1	11/03/2014	001-36710
10.2	Omnibus Agreement dated November 3, 2014 by and among Shell Pipeline Company LP, Shell Midstream Partners, L.P., Shell Midstream Partners GP LLC, Shell Midstream Operating LLC and, solely for the purposes of Articles 4 and 5, Shell Oil Company	8-K	10.2	11/03/2014	001-36710
10.3	Shell Midstream Partners Working Capital Facility Agreement, dated as of October 31, 2014, between Shell Midstream Partners, L.P. and Shell Treasury Centre (West) Inc.	8-K	10.3	11/03/2014	001-36710
10.4#	Shell Midstream Partners GP LLC 2014 Long-Term Incentive Plan	8-K	10.4	11/03/2014	001-36710
10.5	Zydeco Voting Agreement, dated November 3, 2014, between Shell Midstream Partners, L.P. and Shell Pipeline Company LP	8-K	10.5	11/03/2014	001-36710
10.6	Mars Voting Agreement, dated November 3, 2014, between Shell Midstream Partners, L.P. and Shell Pipeline Company LP	8-K	10.6	11/03/2014	001-36710
10.7	Bengal Voting Agreement, dated November 3, 2014, between Shell Midstream Partners, L.P. and Shell Pipeline Company LP	8-K	10.7	11/03/2014	001-36710
21	List of Subsidiaries	S-1/A	21	09/23/2014	333-196850

31.1*	Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
31.2*	Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
32.1**	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
32.2**	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase
101.DEF*	XBRL Taxonomy Extension Definition Linkbase

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed, as of March 24, 2015, by the following persons on behalf of the registrant and in the capacities indicated.

Title of each class		Name of each exchange on which registered
Common Units, Representing Limited Partnership Interests		New York Stock Exchange

Large accelerated filer	¨	Accelerated filer	¨

Non-accelerated filer	x	Smaller reporting company	¨

	Page
Item

PART I
1 and 2. Business and Properties		6
1A. Risk Factors		22
1B. Unresolved Staff Comments		41
3. Legal Proceedings		41
4. Mine Safety Disclosures		41

PART II
5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		42
6. Selected Financial Data		45
7. Management’s Discussion and Analysis of Financial Condition and Results of Operations		45
7A. Quantitative and Qualitative Disclosures About Market Risk		59
8. Financial Statements and Supplementary Data		60
9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		82
9A. Controls and Procedures		82
9B. Other Information		83

PART III
10. Directors, Executive Officers and Corporate Governance		85
11. Executive Compensation		90
12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		94
13. Certain Relationships and Related Transactions, and Director Independence		95
14. Principal Accounting Fees and Services		105

PART IV
15. Exhibits, Financial Statement Schedules		106
Signatures		109


				Marginal Percentage Interest in Distributions
	Target Quarterly Distribution per Unit Target Amount			Unitholders		General Partner
Minimum Quarterly Distribution	$	0.162500			98%		2%
First Target Distribution	above $ 0.162500		up to $ 0.186875		98%		2%
Second Target Distribution	above $ 0.186875		up to $ 0.203125		85%		15%
Third Target Distribution	above $ 0.203125		up to $ 0.243750		75%		25%
Thereafter	above $ 0.243750				50%		50%

		Page
Report of Independent Registered Public Accounting Firm		61
CONSOLIDATED BALANCE SHEETS		62
CONSOLIDATED STATEMENTS OF INCOME		63
CONSOLIDATED STATEMENTS OF CASH FLOWS		64
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY		65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		66

		Total				Less than 1 year				1 year to 3 years				4 years to 5 years				More than 5 years
Operating lease for land		$	1.8			$	0.5			$	1.1			$	0.2			$	—

	2014		2013
Customer A	$	0.9	$	1.1
Customer B		6.3		0.2
Customer C		5.7		1.3
Customer D		—		0.5
Customer E		3.0		—

Name	Age	Position with Shell Midstream Partners GP LLC
Curtis R. Frasier	59	Director, Chairman of the Board of Directors
Margaret C. Montana	60	Director, Chief Executive Officer and President
Susan M. Ward	56	Director, Vice President and Chief Financial Officer
Alton G. Smith	53	Vice President, Operations
Michele F. Joy	59	Vice President, Regulatory and Major Projects
Kevin M. Nichols	46	Vice President, Commercial
Lori M. Muratta	49	Vice President, General Counsel and Secretary
Gerard B. Paulides	51	Director
Paul R. A. Goodfellow	49	Director
Rob L. Jones	56	Director
James J. Bender	58	Director
Carlos A. Fierro	55	Director

Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a))
	(a)		(b)		(c)
Equity compensation plans approved by security holders		—		—		6,000,000
Equity compensation plans not approved by security holders		—		—		—
Total		—		—		6,000,000

Distributions of available cash to our general partner and its affiliates		We generally make cash distributions of 98% to the common and subordinated unitholders pro rata, including SPLC, as holder of an aggregate of 21,475,068 common units (15.6% of all units outstanding), and all of our subordinated units (49% of all units outstanding), and 2% to our general partner, assuming it makes all capital contributions necessary to maintain its 2% general partner interest in us. In addition, if cash distributions exceed the minimum quarterly distribution and target distribution levels, the incentive distribution rights held by our general partner entitle our general partner to increasing percentages of the cash distributions, up to 48% of the cash distributions above the highest target distribution level. Assuming we generate sufficient cash available for distribution to support the payment of the full minimum quarterly distributions on our outstanding units for four quarters, our general partner and its affiliates would receive an annual cash distribution of approximately $1.8 million on the 2% general partner interest and $57.8 million on their common and subordinated units.

Payments to our general partner and its affiliates		Pursuant to our partnership agreement, we reimburse our general partner and its affiliates, including SPLC, for costs and expenses they incur and payments they make on our behalf. Pursuant to the omnibus agreement, we pay an annual fee, initially $8.5 million, to SPLC for general and administrative services. In addition, we incurred $3.6 million of incremental general and administrative expense annually as a result of being a publicly traded partnership. Each of these payments was made prior to making any distributions on our common units.

Withdrawal or removal of our general partner		If our general partner withdraws or is removed, its general partner interest and its incentive distribution rights will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

	millions of dollars
Fees ₁
Audit fees	$	0.7
Audit-related fees		—
Tax fees		—
All other fees		—
Total	$	0.7

		SHELL MIDSTREAM PARTNERS, L.P.

		By: Shell Midstream Partners GP LLC, its general partner

March 24, 2015		/s/ Susan M. Ward
		Susan M. Ward Vice President and Chief Financial Officer

Signature		Title

/s/ Margaret C. Montana		Director, President and Chief Executive Officer Shell Midstream Partners GP LLC (principal executive officer)
Margaret C. Montana

/s/ Susan M. Ward		Director, Vice President and Chief Financial Officer Shell Midstream Partners GP LLC (principal accounting officer and principal financial officer)
Susan M. Ward

/s/ Curtis R. Frasier		Chairman of the Board of Directors Shell Midstream Partners GP LLC
Curtis R. Frasier

/s/Gerard B. Paulides		Director Shell Midstream Partners GP LLC
Gerard B. Paulides

/s/ Paul R.A. Goodfellow		Director Shell Midstream Partners GP LLC
Paul R.A. Goodfellow

/s/ Rob L. Jones		Director Shell Midstream Partners GP LLC
Rob L. Jones

/s/ James J. Bender		Director Shell Midstream Partners GP LLC
James J. Bender

/s/ Carlos A. Fierro		Director Shell Midstream Partners GP LLC
Carlos A. Fierro