Unless the context otherwise requires, references in this report to “Shell Midstream Partners,” “the Partnership,” “us,” “our,” “we,” or similar expressions for the time period from and after November 3, 2014, the closing date of our Initial Public Offering (“IPO”), refer to Shell Midstream Partners, L.P. and its subsidiaries. References to “our general partner” refer to Shell Midstream Partners GP LLC, a wholly owned subsidiary of Shell Pipeline Company LP (“SPLC”). References to “Shell” or “Parent” refer collectively to Royal Dutch Shell plc and its controlled affiliates, other than us, our subsidiaries and our general partner.

The following businesses were acquired from our Parent and accounted for as acquisitions between entities under common control. As such, our consolidated financial statements include the financial results of these businesses, which were derived from the financial statements and accounting records of SPLC and Shell for the periods prior to acquisition. Specifically, such businesses are reflected for the following periods prior to the effective date of such acquisition:

Our consolidated statements of income exclude the results of these businesses from net income attributable to the Partnership for the periods indicated above by allocating these results to our Parent.

Shell Midstream Partners, L.P. is a Delaware limited partnership formed by Shell on March 19, 2014 to own and operate develop and acquire pipelinespipeline and other midstream assets. On November 3, 2014, we completedassets, including certain assets acquired from SPLC and its affiliates. We conduct our IPO.operations through our wholly owned subsidiary Shell Midstream Operating, LLC (“Operating Company”). Our general partner is Shell Midstream Partners GP LLC (“general partner”). Our common units are tradedtrade on the New York Stock Exchange (“NYSE”) under the symbol “SHLX.” As of December 31, 2016, SPLC, through Shell Midstream LP Holdings LLC, owned 21,475,068 common units and 67,475,068 subordinated units, representing a 49.2% limited partner interest in us.  Our subordinated units converted to common units on February 15, 2017. SPLC also owned a 100% interest in Shell Midstream Partners GP LLC, our general partner, which in turn owned 3,618,723 general partner units, representing a 2% general partner interest in us.

The Odyssey pipeline system is an approximately 106-mile105-mile pipeline system for the transportation of crude oil in the offshore eastern Gulf of Mexico to markets in Louisiana. Odyssey provides transportation for major oil producers and from more than 20 different production fields in the eastern Gulf of Mexico. Major production platforms connected to Odyssey include: Delta House operated by LLOG Exploration Company, L.L.C., Ram Powell operated by Shell, Petronius operated by Chevron Corporation, and Horn Mountain operated by Freeport-McMoRan Inc.Anadarko Petroleum Corporation. Crude oil transported via Odyssey is delivered to the Delta pipeline system for further delivery to onshore demand centers at Empire Terminal, Houma Terminal, and Norco and Alliance refineries.

Poseidon’s largest customers are major oil producers who ship from a variety of production fields in the Gulf of Mexico. Each accounts for material throughput on the system, and together these shippers account for 90.0% of the throughput. Poseidon earns income through buy/sell arrangements, pursuant to which it purchases crude oil from its customer at the time the crude oil enters its pipeline system, and then resells the crude oil to the customer at the time the crude oil reaches its destination. At the resell point, Poseidon receives the original purchase price plus an agreed differential (referred to as the buy/sell differential). Many of Poseidon’s customers have dedicated production to the pipeline. Some of Poseidon’s customers have agreed to pay for the transportation of minimum periodic volumes whether or not they actually deliver those volumes for transportation.

The Proteus pipeline system is a 71-milean approximately 70-mile crude oil pipeline with a 425 kbpd capacity and provides transportation for multiple oil producers in the eastern Gulf of Mexico. The pipeline provides access to the Mississippi Canyon area of the Gulf of Mexico from the Thunder Horse and Thunder Hawk platforms to the Proteus SP 89E Platform. Noble Energy Inc.’s Big Bend and Dantzler fields are tied back to Thunder Hawk platform. SPLC is currently building the Mattox pipeline which will connect to Proteus and transport all of the volumes from the recently-sanctioned Appomattox platform. Volumes transported on Proteus move via private oil transportation agreements, which are a mix of term and life-of-lease transportation agreements, rather than posted tariffs.

The Endymion pipeline system, which originates downstream of the Proteus SP 89E Platform, is an 89-mileapproximately 90-mile crude oil pipeline with a 425 kbpd capacity and provides transportation for multiple oil producers in the eastern Gulf of Mexico. Endymion provides access to the Mississippi Canyon area of the Gulf of Mexico and is connected to the LOOP Clovelly storage terminal with access to multiple markets. Endymion leases a cavern from LOOP LLC. Volumes transported on

The Bengal pipeline system is a 159-milean approximately 160-mile refined products pipeline system connecting four refineries in southern Louisiana to long-haul transportation pipelines. The pipeline system consists of two primary pipelines. The 24-inch diameter pipeline has a capacity of 305 kbpd and connects the MotivaShell and Valero refineries in Norco, Louisiana and the Marathon Petroleum Corporation refinery in Garyville, Louisiana to Bengal’s Baton Rouge, Louisiana tankage and the Plantation pipeline. The 16-inch diameter pipeline has a capacity of 210 kbpd and runs from Motiva’sShell's Convent, Louisiana refinery to the Plantation pipeline and Bengal’s Baton Rouge, Louisiana tankage.

The Colonial pipeline system 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.

Since its inception in 1963, Colonial has served a diverse set of customers, including refiners, marketers, airports and airlines. In 2016,2017, more than 100 shippers transported product through Colonial’s system, including an affiliate of Shell. Colonial is subject to FERC regulation and has both market-based rates and rates that are subject to annual adjustment based on the FERC index.

At Lockport, our storage tanks continue to be utilized at 100%80% capacity via three service and throughput contracts. TwoOne of thesethe contracts expireexpired in 2017; they areearly 2017, was extended for one year under revised terms, and is currently under re-negotiation.re-negotiation, and another expired on December 31, 2017 and has been extended one year under revised terms effective January 1, 2018. The third contract expires December 31, 2019. In addition to these three contracts, we are actively developing new business for the facility. Additionally, some contracts also guarantee payments for minimum monthly throughput volumes. A competing pipeline from Flannigan to Patoka, Illinois, owned by Enbridge Inc.Our storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and Marathon Petroleum Company, was completed in the fourth quarter of 2015 primarily to transport Bakken crude oil, which was being previously shipped via railcars. Thisbuilt new pipeline had noconnections, and third parties may construct pipelines that bypass our location, which could have a material adverse material impact on our Lockport operations due to our contracts in place. The use of pipelines to transport Bakken crude oiloperations. However, other developments may eventually increase demand for storage and throughput at Lockport.Lockport as pipelines are used to transport crude types previously shipped in other ways.

On October 20, 2016, the Federal Energy Regulatory CommissionFERC issued an Advance Notice of Proposed Rulemaking (“ANOPR”) in Docket No. RM17-1-000 regarding changes to the oil pipeline rate index methodology and data reporting on the Page 700 of the FERC Form No. 6. In an effort to improve the Commission’s ability to ensure that oil pipeline rates are just and reasonable under the Interstate Commerce Act (“ICA”),ICA, the Commission is considering making the following changes to their current indexing methodologies for oil pipelines:

Initial comments were filed on January 19, 2017, and reply comments will be duewere filed on March 17, 2017. We will continue to monitor developments in this area.

Intrastate services provided by certain of our pipeline systems are subject to regulation by state regulatory authorities, such as the Texas Railroad Commission, which currently regulates Zydeco and Colonial pipeline rates; and the Louisiana Public Service Commission, which currently regulates the Zydeco, Mars, Delta and Colonial pipeline rates. State agencies typically require intrastate petroleum pipelines to file their rates with the agencies and permit shippers to challenge existing rates and proposed rate increases. State agencies may also investigate rates, services, and terms and conditions of service on their own initiative. State regulatory commissions could limit our ability to increase our rates or to set rates based on our costs, or could order us to reduce our rates and require the payment of refunds to shippers.

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

Shippers can always file a complaint with FERC or a state agency challenging rates or conditions of services. If they were successful, FERC or a state agency could order reparations or service charge.

Certain of our pipelines, including Auger, Na Kika, Odyssey, Poseidon, Proteus, Endymion, Cleopatra and parts of Mars, are located offshore in the Outer Continental Shelf. As such, they are not subject to FERC or state rate regulation, but are subject to the Outer Continental Lands Act (“OCSLA”). Under the OCSLA, we must provide open and nondiscriminatory access to both pipeline owner and non-owner shippers, and comply with other requirements.  

Our assets are subject to increasingly strict safety laws and regulations. Our transportation and storage of crude oil, and refined products, involveand dry gas involves a risk that hazardous liquids or gas may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages, liability and/or reparations to land owners and significant business interruption. The Pipeline and Hazardous Materials Safety Administration (“PHMSA”)PHMSA of the Department of Transportation (“DOT”)DOT has adopted safety regulations with respect to the design,

We are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968 (“NGPSA”) and the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”). The NGPSA delegated to PHMSA through DOT the authority to regulate gas pipelines. The HLPSA delegated to PHMSA through DOT the authority to develop, prescribe, and enforce federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in High Consequence Areas (“HCAs”).HCAs. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. The Pipeline Safety Improvement Act of 2002 established mandatory inspections for all United StatesU.S. oil transportation pipelines, and some gathering lines in HCAs. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquids pipelines and pipeline control room management. WeThese assets are also subject to the Pipeline Safety Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines, and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In 2016, the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the “Pipes Act”) was enacted. The Pipes Act reauthorized the PHMSA through 2019 and imposed a few new mandates on the agency. The law provided the Secretary of the DOT the power to issue pipeline industry wide emergency orders if an incident poses or exposes a particular widespread problem. It also required the PHMSA to develop regulations for the construction and operations of underground natural gas storage facilities and instructed the PHMSA to finish the tasks left over from the 2011 bill.

PHMSA administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of hazardous liquids by pipeline, including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced, or otherwise changed (Subparts C and D of 49 CFR § 195); pressure testing of new pipelines (Subpart E of 49 CFR § 195); operation and maintenance of pipeline systems, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs, and managing the operation of pipeline control rooms (Subpart F of 49 CFR § 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR § 195); and integrity management requirements for pipelines in HCAs (49 CFR § 195.452). On January 13, 2017, PHMSA announced the

The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act of 2011, as well as any implementation of PHMSA rules thereunder, could require us to install new or modified safety controls, pursue additional capital projects, or conduct maintenance programs on an accelerated basis; any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or

We monitor the structural integrity of our pipelines through a program of periodic internal assessments using a variety of internal inspection tools, as well as hydrostatic testing that conforms to federal standards. We accompany these assessments with a comprehensive data integration effort and repair anomalies, as required, to ensure the integrity of the pipeline. We conduct a thorough review of risks to the pipelines and perform sophisticated calculations to establish an appropriate reassessment interval for each pipeline. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards and continually monitor, test and record the effectiveness of these corrosion inhibiting systems.  We have robust third party damage prevention and public awareness programs to help protect our lines from the risk of excavation and other outside force damage threats. Our tanks are inspected on a routine basis in compliance with PHMSA and U.S. Environmental Protection Agency (“EPA”)EPA regulations. Every tank periodically receives a full out of service, internal inspection per American Petroleum Institute standard 653 and is repaired as necessary.

In general terms, the prices of crude oil and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors impacting crude oil prices include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; the availability of imported crude oil; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; actions by the Organization of the Petroleum Exporting Countries (“OPEC”) and other oil producing nations; the price and availability of alternative fuels; the effect of energy conservation measures; the strength of the U.S. dollar; the nature and extent of governmental regulation and taxation; and the anticipated future prices of crude oil and other commodities.

A substantial portion of our revenue is derived from long-term transportation service agreements with shippers, including ship-or-pay agreements and life-of-lease transportation agreements, some of which provide a guaranteed return, and storage service agreements with marketers, pipelines and refiners. We believe the commercial terms of these long-term transportation and storage service agreements substantially mitigate volatility in our cash flowsfinancial results by limiting our direct exposure to reductions in volumes due to supply or demand variability. Our business can, however,could be negatively affected if we are unable to renew or replace our contract portfolio on comparable terms, by sustained downturns or sluggishness in commodity prices or the economy in general, and is impacted by shifts in supply and demand dynamics, the mix of services requested by the customers of our pipelines, competition and changes in regulatory requirements affecting our operations. Our business can also be impacted by asset integrity or customer interruptions and natural disasters.

Similarly, our refined products pipelines have the ability to serve multiple major demand centers. Our refined products shippers periodically change the relative mix of refined products shipped on our refined products pipelines, as well as the destination points, based on changes in pricing and demand dynamics. While these changes in shipping patterns are reflected in relative types of refined products handled by our various pipelines, our total product transportation revenue is primarily affected by changes in overall refined products supply and demand dynamics. Demand can also be greatly affected by refinery performance in the end market, as refined products pipeline demand will increase to fill the supply gap created by refinery issues.

We can also be constrained by asset integrity considerations in the volumes we ship. We may elect to reduce cycling on our systems to reduce asset integrity risk, which in turn would likely result in lower revenues.

Since the beginning of the fourth quarter of 2017, fields connecting to Odyssey have been offline due to operational issues, causing an impact of approximately $3.5 million to net income and cash available for distribution in 2017 for Odyssey and Delta. It is expected that they will remain offline through at least the first quarter of 2018. The estimated impact to net income and cash available for distribution is approximately $4.5 million and $1.5 million in the first and second quarters of 2018, respectively.

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 ofWhile we do see some variation from quarter-to-quarter resulting from changes in our customers’ demand for transportation, this risk has historically been mitigated by the long-term, fixed rate basis upon which we have contracted a substantial majorityportion of our capacity being reservedcapacity. However, contracts representing approximately 30.0% of our revenues for the year ended December 31, 2017 will expire in 2018 and 2019. Our business may be negatively affected if we are unable to renew or replace our contract portfolio on a long-term, fixed-rate basis, our revenue is not significantly affected by variation in customers’ actual usage.comparable terms.

Our Lockport storage terminal competes with surrounding providers of storage tank services. Some of our competitors have expanded terminals and built new pipeline connections, and third parties may construct pipelines that bypass our location. These, or similar events, could have a material adverse impact on our Lockport operations due tooperations.