Exhibit

EX-99.1 3 ex991.htm ITEMS 1, 6, 7 & 8 FROM 10-K REVISED TO REFLECT RECAST SEGMENT INFORMATION Exhibit



BUSINESS

EXHIBIT 99.1

EXPLANATORY NOTE

We changed our operating segment presentation in the first quarter of 2017 to reflect our expanded gathering and processing assets and operations and how our chief operating decision maker (“CODM”) manages our business. With the completion of the acquisition of the crude oil, natural gas and produced water gathering systems and two natural gas processing facilities from Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Energy Midstream, LLC (“North Dakota Gathering and Processing Assets”) on January 1, 2017, our gathering and processing assets and operations expanded significantly and enhanced our ability to offer integrated gathering and processing services to our customers. Given the business’s focus on providing integrated services along with the revised reporting structure implemented by management to assess performance and make resource allocation decisions, we have determined our operating segments, which are the same for reporting purposes, are the (i) Gathering and Processing segment and (ii) Terminalling and Transportation segment. The Gathering and Processing segment information has been recast to reflect our current presentation. There were no changes to the categorization of assets within our Terminalling and Transportation segment.

In addition, as part of the CODM’s reevaluation of how it monitors and evaluates the business and allocates resources, management revised its methodology for the allocation of corporate general and administrative expenses which resulted in additional corporate costs being allocated to our Gathering and Processing segment for certain administrative activities associated with our gathering and processing business in the Rockies region. The change to our Terminalling and Transportation segment was nominal.

The items herein included in the Form 10-K for the three years ended December 31, 2016, have been recast for the segment changes described above.

Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Tesoro Logistics LP, one or more of its consolidated subsidiaries or all of them taken as a whole. Unless the context otherwise requires, references in this report to “Tesoro” or our “Sponsor” refer collectively to Tesoro Corporation and any of its subsidiaries, other than TLLP, its subsidiaries and its general partner.

PART I

ITEM 1. BUSINESS

We completed our initial public offering (the “Initial Offering”) in April 2011. We have since acquired additional assets from Tesoro, and those assets, liabilities and results of operations are collectively referred to as the “Predecessors.” Our financial information for all periods, except the consolidated balance sheet as of December 31, 2016, includes the historical results of our Predecessors and the results of TLLP. The financial statements of our Predecessors have been prepared from the separate records maintained by Tesoro and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Most notably, this applies to the revenue associated with the terms of the commercial agreements as our Predecessors generally did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment.

We are a full-service logistics company operating primarily in the western and mid-continent regions of the United States. We own and operate networks of crude oil, refined products and natural gas pipelines, terminals with dedicated and non-dedicated storage capacity for crude oil and refined products, rail facilities with loading and off-loading capabilities, marine terminals, a trucking fleet, natural gas processing and fractionation complexes. Our assets are organized in two segments: Gathering and Processing and Terminalling and Transportation. Segment disclosures are discussed in Note 13 to our consolidated financial statements in Item 8. Our business is affected by seasonality due to weather conditions and access restrictions, as well as supply and demand.

We generate revenues by charging fees for gathering crude oil and natural gas, for terminalling, transporting and storing crude oil and refined products and for processing natural gas. We do not engage in the trading of crude oil, natural gas, natural gas liquids (“NGLs”) or refined products; therefore, we have minimal direct exposure to risks associated with commodity price fluctuations as part of our normal operations. However, we may be subject to nominal commodity risk exposure due to pipeline loss allowance provisions in many of our pipeline gathering and



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transportation contracts and a nominal amount of condensate retained as part of our natural gas gathering services. In the event actual measured pipeline losses are less than the loss allowance we are able to sell the natural gas and crude oil at market price adjusted for premiums; correspondingly, when actual losses exceed loss allowances we purchase natural gas or crude oil at market prices. The natural gas imbalance exposes us to some fluctuations in natural gas prices. At December 31, 2016, the estimated value of the imbalance was less than $1 million. For the NGLs that we handle under keep-whole agreements, the Partnership has a fee-based processing agreement with Tesoro, which minimizes the impact of commodity price movements during the annual period subsequent to renegotiation of terms and pricing.

We are not a taxable entity for federal and state income tax purposes. Instead, each partner is required to take into account its share of our income, gain, loss and deduction in computing its federal and state income tax liabilities, regardless of whether we make cash distributions to the partner. The taxable income reportable to each partner takes into account differences between the tax bases and financial reporting bases of assets and liabilities, the acquisition price of their units and the taxable income allocation requirements under the partnership agreement.

NORTH DAKOTA GATHERING AND PROCESSING ASSETS. On November 21, 2016, we agreed to acquire crude

oil, natural gas and produced water gathering systems and two natural gas processing facilities from Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Energy Midstream, LLC, the North Dakota Gathering and Processing Assets, for total consideration of approximately $700 million. The North Dakota Gathering and Processing Assets include over 650 miles of crude oil, natural gas, and produced water gathering pipelines, 170 million cubic feet per day (“MMcf/d”) of natural gas processing capacity and 18.7 thousand barrels per day (“Mbpd”) of fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. The acquisition closed on January 1, 2017. With this acquisition, we expanded the assets in our Gathering and Processing segments located in the Williston Basin area of North Dakota to further grow our integrated, full-service logistics capabilities in support of third-party demand for crude oil, natural gas and water gathering services as well as natural gas processing services. In addition, this extends our capacity and capabilities by adding new origin and destination points for our common carrier pipelines in North Dakota and extends our crude oil, natural gas and water gathering and associated gas processing footprint to enhance and improve overall basin logistics efficiencies.



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The following provides an overview of our assets and operations in relation to Tesoro’s refineries:

GATHERING AND PROCESSING

Our Gathering and Processing segment consists of gathering systems including crude oil, natural gas and water pipeline gathering systems in the Bakken Shale/Williston Basin area of North Dakota and Montana (the “Bakken Region”) and the Green River Basin, Vermillion Basin and Uinta Basin in the states of Utah, Colorado and Wyoming, including:


•	a common carrier crude oil gathering and transportation system in North Dakota and Montana (the “High Plains System”);


•	North Dakota Gathering Systems, which consists of a crude oil and natural gas gathering system located in and around the Williston Basin;


•	Uinta Basin Gathering System, which consists of natural gas gathering systems and compression assets located in northeastern Utah;


•	Green River System, consisting of an integrated natural gas gathering and transportation system;


•	Vermillion Gathering System, which consists of natural gas gathering and compression assets located in Southern Wyoming, northwest Colorado and northeast Utah; and


•	certain equity method investments that contribute to our gathering systems including investments in:


◦	Rendezvous Gas Services, L.L.C. (“RGS”), which operates the infrastructure that transports gas from certain fields to several re-delivery points, including natural gas processing facilities that are owned by TLLP or a third party;


◦	Three Rivers Gathering, LLC, which transports natural gas to our natural gas processing facilities in the Uinta Basin; and



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◦	Uintah Basin Field Services, L.L.C., which operates gathering pipeline and gas compression assets located in the southeastern Uinta Basin.

GATHERING AND PROCESSING - VOLUMES TRANSPORTED IN 2016

HIGH PLAINS SYSTEM. We own and operate a common carrier crude oil gathering and transportation system consisting of common carrier pipelines in North Dakota and Montana (the “High Plains Pipeline”), which gathers and transports crude oil into major regional takeaway pipelines and refining centers including Tesoro’s North Dakota refinery in Mandan. The Partnership transports crude oil processed at Tesoro’s Mandan refinery via the High Plains System.

As part of our High Plains System, we own storage facilities with tanks located in strategic areas of the Bakken Region basins, which provide our customers access to and from multiple pipelines and rail loading facilities in the area. The current storage capacity is over 1 million barrels.

In addition, we own and operate a truck-based crude oil gathering operation. This operation uses a combination of proprietary and third-party trucks, all of which we dispatch and schedule. These trucks gather and transport crude oil from well sites or nearby collection points in the Bakken Region and deliver it to our High Plains Pipeline and third-party destinations. We charge per-barrel tariffs and service fees for receiving and transporting crude oil, for dispatching and scheduling proprietary and third-party trucks and for use of our field unloading tanks.

NORTH DAKOTA GATHERING SYSTEMS. The North Dakota Gathering Systems are crude oil, natural gas and produced water gathering systems located in and around the Williston Basin in McLean County, North Dakota, including the North Dakota Gathering and Processing Assets. These systems are primarily supported by long-term, fee-based, crude oil and natural gas gathering agreements with minimum volume commitments and backed by acreage dedications from producers. Included are the recently acquired North Dakota Gathering and Processing Assets.

UINTA BASIN GATHERING SYSTEM. The Uinta Basin Gathering System consists of natural gas gathering systems and compression assets located in northeast Utah, which include low-pressure natural gas gathering pipeline and compression. We refer to these individual gas gathering systems collectively as the Uinta Basin Gathering System. The gathering system is primarily supported by acreage dedications and long-term, fee-based gathering agreements that contain annual inflation adjustment mechanisms and minimum volume commitments.

GREEN RIVER SYSTEM. The Green River System, located in western Wyoming, consists of three integrated assets: the Green River Gathering Assets, the assets owned by Rendezvous Pipeline Company, LLC (“Rendezvous Pipeline”) and assets owned by RGS. In addition to gathering natural gas, the system also gathers crude oil production, transports the crude oil to an interstate pipeline interconnect, and gathers and handles produced and flowback water associated with well completion and production activities.


•	The Green River Gathering Assets are primarily supported by contracts that remain in effect as long as commercial production of hydrocarbons is ongoing (“Life-of-Reserves Contracts”) and long-term, fee-based gathering agreements with minimum volume commitments.


•	Rendezvous Pipeline provides gas transportation services from the Blacks Fork processing complex in southwest Wyoming to an interconnect with the Kern River Pipeline. The capacity on the Rendezvous Pipeline system is contracted under long-term take or pay transportation contracts.


•	RGS, which operates the infrastructure that transports gas from certain fields to several re-delivery points, including natural gas processing facilities that are owned by TLLP or a third party.

VERMILLION GATHERING SYSTEM. The Vermillion Gathering System consists of gas gathering and compression assets located in southern Wyoming, northwest Colorado and northeast Utah. The Vermillion Gathering System is primarily supported by Life-of-Reserves Contracts and long-term, fee-based gas gathering agreements with minimum volume commitments.



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PIPELINE MILES BY GATHERING SYSTEM


(a)	Includes the gathering pipelines associated with the North Dakota Gathering and Processing Assets acquisition.

Our natural gas operations are affected by seasonal weather conditions and certain access restrictions imposed by the Bureau of Land Management (“BLM”) on federal lands to protect migratory and breeding patterns of native species. During the winter months, our customers typically reduce drilling and completion activities due to adverse weather conditions. Also, access restrictions imposed by the BLM reduce our ability to complete expansion projects and connect to newly completed wells. We mitigate these seasonal risks in affected areas through prudent planning and coordination with our customers to ensure expansion projects are completed prior to these periods. Condensate sales, however, tend to increase in the first quarter of each year, as the colder ground causes more condensates to fall out of the gas stream in our gathering system. However, this impact is minimal and we expect such seasonality to diminish as we continue expanding our existing assets or acquire additional assets outside of the affected areas.

Our Gathering and Processing segment also consists of the Vermillion processing complex (“Vermillion Complex”), the Uinta Basin processing complex (“Uinta Basin Complex”), the Blacks Fork processing complex (“Blacks Fork Complex”), the Emigrant Trail processing complex (“Emigrant Trail Complex”) as well as the Robinson Lake processing complex (“Robinson Lake Complex”) and the Belfield processing complex (“Belfield Complex”) that were

acquired with the North Dakota Gathering and Processing Assets. We process gas for certain producers under keep-whole processing agreements. Approximately 45-50% of our plant production is currently supported by long-term, fee-based processing agreements with minimum volume commitments. The graph below shows the throughput capacities of our processing and fractionation facilities.

VERMILLION COMPLEX. The Vermillion Complex, located in Sweetwater County, Wyoming, consists of two processing trains. A portion of the natural gas volumes we gather at the Vermillion Complex is available to us pursuant to natural gas gathering agreements with several producer customers. The plant receives the majority of its gas from the Vermillion sub-basin in southern Wyoming and northwest Colorado.

UINTA BASIN COMPLEX. The Uinta Basin Complex, located in Uintah County, Utah, consists of five separate processing trains with raw gas inlet processing capacity. The complex receives the majority of its gas from various natural gas fields located in the Uinta Basin.

BLACKS FORK COMPLEX. The Blacks Fork Complex, located in Sweetwater and Uinta Counties, Wyoming, consists of three separate gas processing trains and a NGLs fractionation facility. The complex receives the majority of its gas from various gas fields located in the Green River Basin of western Wyoming.

EMIGRANT TRAIL COMPLEX. The Emigrant Trail Complex, located in Uinta County, Wyoming, consists of one cryogenic gas processing train. The complex receives the majority of its gas from various gas fields located in the Green River Basin of western Wyoming.

ROBINSON LAKE COMPLEX. The Robinson Lake Complex is located in Montrail County, North Dakota, and consists of compression units, propane refrigeration plants and a fractionation plant. The complex receives the majority of its gas from various gas fields located in the Williston Basin of North Dakota.

BELFIELD COMPLEX. The Belfield Complex, located in Billings, Dun and Stark Counties, North Dakota, consists of compression units, propane refrigeration plants and a fractionation plant. The complex receives the majority of its gas from various gas fields located in the Williston Basin of North Dakota.



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THROUGHPUT CAPACITY BY PROCESSING COMPLEX (a)


(a)	Capacity is measured in MMcf/d.


(b)	We have fractionation throughput capacity at our Blacks Fork complex, Robinson Lake complex and our Belfield complex of 15.0 Mbpd, 11.5 Mbpd and 7.2 Mbpd, respectively.


(c)	Included with the North Dakota Gathering and Processing Assets acquisition.

TERMINALLING AND TRANSPORTATION

We generate terminalling and transportation revenues by charging our customers fees for:


•	delivering crude oil, refined products and intermediate feedstocks from vessels to refineries and terminals;


•	loading and unloading crude oil transported by unit train to Tesoro’s Anacortes refinery;


•	marine loading and unloading;


•	providing storage services;


•	transferring refined products from terminals to trucks, barges and pipelines;


•	transporting refined products;


•	providing ancillary services, ethanol blending and additive injection, and for barge loading or unloading fees; and


•	handling petroleum coke for Tesoro’s Los Angeles refinery.

Our refined products terminals are supplied by our pipelines, Tesoro-owned and third-party pipelines, trucks, and barges. Our marine terminals load and unload vessels, our rail car loading and unloading facilities receive crude oil transported on unit trains leased by Tesoro, and our petroleum coke facility handles and stores petroleum coke.

TERMINALLING

The following chart shows the average daily terminalling or loading capacity and total average terminalling throughput for our crude oil and refined products terminals (in Mbpd) for the year ended December 31, 2016.

The following table shows the locations and types of products handled by our crude oil and refined products terminals and storage facilities including their storage capacities (in shell barrels) as of December 31, 2016.



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Terminal Location	Products Handled	Total Approximate Storage Capacity (a)	Dedicated Storage (b)
California Marine Terminals	Crude Oil; Intermediate Feedstocks; Gasoline; Diesel; Jet Fuel	3,349,000	2,231,000
California Terminals and Storage Facilities	Crude Oil; Diesel; Intermediate Feedstocks; Gasoline; Gasoline Blendstocks; Jet Fuel; Light Ends; NGLs	20,159,000	17,154,486
Idaho	Gasoline; Diesel; Jet Fuel	878,000	53,826
Utah	Gasoline; Diesel; Jet Fuel; Crude Oil Storage; Truck Unloading	895,000	878,000
Washington	Gasoline; Diesel; NGLs	2,374,000	1,602,977
Alaska	Gasoline; Diesel; Jet Fuel; Aviation Gasoline	5,563,000	4,156,424
Total Crude Oil and Refined Products		33,218,000	26,076,713


(a)	Includes storage capacity for refined products and ethanol only; excludes additive storage for gasoline and diesel.


(b)	Represents dedicated portion of total storage capacity for which we charge a per barrel monthly fee based on storage capacity.

CALIFORNIA MARINE TERMINALS. The California marine terminals support Tesoro’s Los Angeles refinery, Tesoro’s Martinez refinery and third parties. The Los Angeles marine terminals consist of three marine terminals and a marine storage facility. One of the marine terminals, Berth 121, is capable of handling VLCC class ships. Another marine terminal is Terminal 2, which is comprised of a berth dock and is adjacent to our Terminal 3 storage facility. The third is a marine terminal currently subleased from Tesoro pursuant to a master lease between Tesoro and the City of Long Beach, which expires in 2032. Tesoro currently leases a portion of Berth 121 from the City of Long Beach under a lease that expires in 2023 and a portion of Terminal 2, which is currently under a month to month lease while negotiations are underway to provide a long term lease. Until the effectiveness of the subleases between Tesoro and us for these properties, we are operating the assets pursuant to the Berth 121 Operating Agreement and the Terminals 2 and 3 Operating Agreement.

The Martinez Crude Oil Marine Terminal is located near Tesoro’s Martinez refinery and consists of a dock, storage tanks and related pipelines that receive crude oil from vessels for delivery to Tesoro’s refinery and a third-party terminal. The dock and related leasehold improvements are situated on an offshore parcel of land that is currently being leased by Tesoro from the California State Lands Commission under a term lease. The lease will be legally transferred to

us upon renewal and approval from the California State Lands Commission. We are currently operating these assets under the terms of the Amorco Marine Terminal Use and Throughput Agreement entered into in April 2012.

On November 21, 2016, we purchased the assets located at the Avon marine terminal facility (the “Avon Marine Terminal Assets”), consisting of a berth dock that serves as the main shipping and receiving point for Tesoro’s Martinez refinery for the transfer of waterborne non-crude feedstocks, is the principal outbound marine delivery point for refined products and is directly connected to the refined products tankage located at the refinery. We are currently operating these assets under the terms of the Avon Marine Terminal Operating Agreement.

In connection with the Avon Marine Terminal Assets, Tesoro Logistics Operations LLC, our subsidiary (“TLO”), entered into an operating agreement that is intended to be treated as a contribution of the Avon Marine Terminal Assets (including all economic benefits and burdens relating to those assets) as of the closing date on November 21, 2016.

CALIFORNIA TERMINALS AND STORAGE FACILITIES. We own and operate terminals and storage facilities in California. In addition, we operate a refined products terminal in Stockton, which we lease from the Port of Stockton under a five-year lease expiring in 2019 that can be extended for up to two additional five-year terms. We own and operate a terminal located at Tesoro’s Martinez refinery that includes a refined products truck rack, a NGLs truck facility and a NGLs rail loading and unloading facility. The Martinez terminal receives refined products via pipelines from the Martinez refinery, some of which we blend with renewable fuels before delivery. In November 2015, we purchased crude oil and refined product storage and pipeline assets in Los Angeles, California from Tesoro, which included crude oil, feedstock, and refined product storage tanks with combined capacity of 6.6 million barrels and a 50% fee interest in a pipeline that transports jet fuel from Tesoro’s Los Angeles refinery to the Los Angeles International Airport.



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On November 21, 2016, we purchased certain terminalling and storage assets located in Martinez, California (the “Northern California Terminalling and Storage Assets”) from Tesoro consisting of:


•	tankage with shell capacity of approximately 5.8 million barrels of crude oil, feedstock, and refined product storage located at Tesoro’s Martinez refinery, together with all related equipment and ancillary facilities used for the operation thereof (the “Tankage”);


•	the Avon Marine Terminal Assets; and


•	the pipelines, causeway and ancillary equipment that connect the Tankage to the Avon Marine Terminal, as well as all associated easements, permits and licenses.

In connection with the Northern California Terminalling and Storage Assets purchase, we entered into certain commercial agreements with Tesoro and its subsidiary Tesoro Refining and Marketing Company (“TRMC”), our general partner and TLO, as applicable.

CARSON CALIFORNIA PETROLEUM COKE HANDLING AND STORAGE FACILITY. We own and operate a coke handling and storage facility adjacent to Tesoro’s Los Angeles refinery. Tesoro has committed to throughput 2,600 metric tons per day of petroleum coke at this facility. We lease the facility to Tesoro under an agreement that expires in 2024 and can be renewed by Tesoro for six renewal terms of ten years each.

IDAHO TERMINALS. We own and operate terminals in Idaho, including terminals located in Boise, Pocatello and Burley. Refined products received at the Idaho terminals are distributed by Tesoro and third parties through the truck loading racks.

UTAH TERMINALS. We own and operate a refined products terminal adjacent to Tesoro’s Utah refinery. The Salt Lake City terminal has the ability to receive refined products directly from the refinery via pipeline. Refined products received and ethanol blended into gasoline at this terminal are sold locally and regionally by Tesoro through our truck loading rack. We own and operate a crude oil truck terminal that allows us to receive black wax crude oil for Tesoro’s use in its Utah refinery. We also own and operate a crude oil and refined products storage facility in Salt Lake City with 878,000 barrels of storage capacity. The storage tanks are connected to Tesoro’s Salt Lake City refinery through our four interconnecting pipelines, but are not directly connected to our Salt Lake City terminal. The storage facility supplies crude oil to Tesoro’s Utah refinery and receives refined and intermediate products from the refinery.

WASHINGTON TERMINALS AND STORAGE FACILITIES. Our Washington terminals consist of three terminals located in Vancouver, Pasco and Anacortes. The Vancouver terminal is leased from the Port of Vancouver under a 10-year lease expiring in 2026, with one 10-year renewal option. We receive gasoline and distillates at this terminal from Tesoro’s Anacortes refinery through a third-party common carrier pipeline. We also have access to a marine dock owned by the Port of Vancouver under a non-preferential berthing agreement, which allows us to receive gasoline and distillates from Tesoro’s Anacortes refinery and third-party sources through barge deliveries and to transport those refined products to the terminal on proprietary interconnecting pipelines. Refined products received at this terminal are sold locally by Tesoro and others through our truck loading rack or through barges loaded at the Port of Vancouver dock.

Our Pasco terminal is supplied with refined products from our Northwest Products Pipeline and can receive refined products delivered by barge via the Columbia River. The refined products received by the terminal can be delivered to Spokane, Washington via the Northwest Products Pipeline or distributed via truck from its truck rack.

The Anacortes assets consist of a refined products truck terminal, a NGLs truck terminal, a NGLs rail loading and unloading facility, light products truck rack and crude and heavy oil storage tanks with a shell capacity of approximately 1.5 million barrels, all located at Tesoro’s Anacortes refinery. The Anacortes terminal is included in the real property leased under the agreement with Tesoro for the Anacortes Rail Facility.

The Anacortes Rail Facility in Washington includes an unloading platform with receiving and departing tracks capable of handling a train, as well as additional short track spurs. The facility, which was placed in service in September 2012, has a permitted capacity to unload up to an annual average of 50 Mbpd of crude oil to Tesoro’s Anacortes refinery. We entered into an agreement with Tesoro to lease its real property at the Anacortes Rail Facility for a term of ninety-nine years.



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NORTH DAKOTA TERMINAL. We own and operate a refined products terminal located at Tesoro’s Mandan refinery. The terminal receives product directly from Tesoro’s Mandan refinery.

ALASKA TERMINALS AND STORAGE FACILITIES. Our Alaska terminals consist of five terminals located in Anchorage and Nikiski. The Anchorage terminal is located on property at two adjacent leaseholds within the Port of Anchorage. A portion of the terminal is on land leased from the Alaska Railroad Corporation through December 31, 2021. We may renew the lease for one additional five-year term. The remainder of the terminal is on land we lease from the Municipality of Anchorage through November 1, 2035. We may renew the lease for up to two additional five-year terms. This terminal has the ability to receive refined products from Tesoro’s Alaska refinery through our state-regulated common carrier pipeline and from marine vessels through the Port of Anchorage. The terminal also has a rail rack that is leased to a third party. It can hold and unload rail cars and is connected to a pipeline that runs to a neighboring third-party jet fuel storage facility. Refined products received at the terminals are sold locally by Tesoro and others through separate truck loading racks, through third-party barges loaded at a Port of Anchorage dock or through pipelines to a third-party storage facility. The Nikiski terminal includes a truck rack and storage tanks with approximately 212,000 barrels of storage capacity. The terminal is supplied with refined products by a direct pipeline from Tesoro’s Kenai refinery.

On July 1, 2016, we entered into an agreement with Tesoro, our general partner, TLO and Tesoro Alaska Company LLC, a subsidiary of Tesoro (“TAC”), pursuant to which TAC agreed to contribute to TLO certain terminalling and storage assets (the “Alaska Storage and Terminalling Assets Purchase”). The terminalling and storage assets include:


•	tankage with a shell capacity of approximately 3.5 million barrels located at TAC’s refinery in Kenai, Alaska, related equipment and ancillary facilities used in the operation thereof;

•

all of TAC’s limited liability company interests in Tesoro Alaska Terminals LLC, a wholly-owned subsidiary of TAC, which owns (i) a bulk tank farm and terminal facility located at the Port of Anchorage in Anchorage, Alaska with 580 thousand barrels of in-service storage capacity for refined products, a truck rack and a rail-loading facility, and (ii) a terminal facility located at the Fairbanks International Airport in Fairbanks, Alaska, with 22.5 thousand barrels of in-service capacity for refined products and a truck rack; and


•	certain related assets used in connection with the foregoing assets.

In connection with the Alaska Storage and Terminalling Assets Purchase, we entered into certain commercial agreements with Tesoro, TAC, our general partner, TRMC and TLO, as applicable.

TRANSPORTATION

We own and operate the Northwest Products Pipeline, a common carrier refined products pipeline that is the primary transportation option from Salt Lake City to Idaho and eastern Washington, a refined products pipeline connecting Tesoro’s Kenai refinery to Anchorage, Alaska and a southern California transportation pipeline system. We also own a number of proprietary pipelines in Salt Lake City and Los Angeles that transport a number of products between various facilities, including Tesoro’s refineries, and other owned and third-party terminals and pipelines. The chart below shows the total average throughput utilized by Tesoro and third parties for transportation services on our crude oil and refined products pipelines for the year ended December 31, 2016.

TLLP TRANSPORTATION VOLUME (in Mbpd)



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COMMERCIAL AGREEMENTS

TESORO

Tesoro accounted for $715 million, or 59%, of our total revenues in the year ended December 31, 2016. No revenue was recorded by the Predecessors for transactions with Tesoro in the Terminalling and Transportation segment prior to the Acquisitions from Tesoro during the year ended December 31, 2016.

We process gas for certain producers under keep-whole processing agreements. Under a keep-whole agreement, normally a producer would transfer title of the NGLs produced during gas processing and the processor, in exchange, would deliver to the producer natural gas with a British Thermal Unit (“BTU”) content equivalent to the NGLs that would be removed. However, TLLP entered into an agreement with Tesoro, which transfers the commodity risk exposure associated with these keep-whole processing agreements from TLLP to Tesoro (the “Keep-Whole Commodity Agreement”). Under the Keep-Whole Commodity Agreement with Tesoro, Tesoro pays TLLP a processing fee for NGLs related to keep-whole agreements and delivers the replaced natural gas to the producers on behalf of TLLP. TLLP pays Tesoro a marketing fee in exchange for assuming the commodity risk. See Note 3 to our consolidated financial statements in Item 8 for additional information on our keep-whole agreements.

We have various long-term, fee-based commercial agreements with Tesoro, under which we provide pipeline transportation, trucking, terminal distribution, storage services and coke handling services to Tesoro. See Note 3 to our consolidated financial statements in Item 8 for additional information on our commercial agreements.

THIRD-PARTIES

Third-party agreements accounted for $505 million, or 41%, of our total revenues for the year ended December 31, 2016. Of this, approximately $337 million is under committed arrangements in which we provide gathering, processing, pipeline transportation, terminal distribution and storage services. QEP Resources accounted for 13% of our total revenues in the year ended December 31, 2016.

COMPETITION

GATHERING AND PROCESSING. Our High Plains System competes with a number of transportation companies for gathering and transporting crude oil produced in the Bakken Region. We may also compete for opportunities to build gathering lines from producers or other pipeline companies. Other companies have existing pipelines that are available to ship crude oil and continue to (or have announced their intent to) expand their pipeline systems in the Bakken Region. We also compete with third-party carriers that deliver crude oil by truck.

Although we compete for third-party shipments of crude oil on our High Plains System, our contractual relationship with Tesoro under our Transportation Services Agreement (High Plains System) (the “High Plains Pipeline Transportation Services Agreement”) and our connection to Tesoro’s Mandan refinery provide us a strong competitive position in the Bakken Region.

Our competitors for natural gas gathering and processing include other midstream companies and producers. Competition for natural gas volumes is primarily based on reputation, commercial terms, reliability, service levels, flexibility, access to markets, location, available capacity, capital expenditures and fuel efficiencies. In addition to competing for crude oil and natural gas volumes, we face competition for customer markets, which is primarily based on the proximity of the pipelines and facilities to the markets, price and assurance of supply.

TERMINALLING AND TRANSPORTATION. Our competition primarily comes from independent terminal and pipeline companies, integrated petroleum companies, refining and marketing companies and distribution companies with marketing and trading arms. Competition in particular geographic areas is affected primarily by the volumes of refined products produced by refineries located in those areas, the availability of refined products and the cost of transportation to those areas from refineries located in other areas.

We may compete with third-party terminals for volumes in excess of minimum volume commitments under our commercial agreements with Tesoro and third-party customers as other terminals and pipelines may be able to supply Tesoro’s refineries or end user markets on a more competitive basis, due to terminal location, price, versatility and services provided. If Tesoro’s customers reduced their purchases of refined products from Tesoro due to the increased availability of less expensive product from other suppliers or for other reasons, Tesoro may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which would decrease our revenues.



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PIPELINE, TERMINAL AND RAIL SAFETY

PIPELINE SAFETY. Our pipelines, gathering systems and terminal operations are subject to increasingly strict safety laws and regulations. The transportation and storage of refined products, natural gas and crude oil involve a risk that hazardous liquids or natural gas may be released into the environment, potentially causing harm to the public or the environment. The U.S. Department of Transportation, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and state agencies, enforces safety regulations governing the design, construction, operation, maintenance, inspection and management of our pipeline and storage facilities. These regulations require the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the investigation of anomalies and if necessary, corrective action. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

We may incur significant costs and liabilities associated with repair, remediation, preventative or mitigation measures associated with our pipelines. These costs and liabilities might relate to repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during such repairs. Additionally, if we fail to comply with PHMSA or comparable state regulations, we could be subject to penalties and fines. If future PHMSA regulations impose new regulatory requirements on our assets, the costs associated with compliance could have a material effect on our operations.

While we operate and maintain our pipelines consistent with applicable regulatory and industry standards, we cannot predict the outcome of legislative or regulatory initiatives, which could have a material effect on our operations, particularly by extending more stringent and comprehensive safety regulations to pipelines and gathering lines not previously subject to such requirements. While we expect any legislative or regulatory changes to allow us time to comply with new requirements, costs associated with compliance may have a material effect on our operations.

NATURAL GAS PROCESSING SAFETY. Our natural gas processing plants and operations are subject to safety regulations under the U.S. Occupational Safety Health Administration (“OSHA”) and comparable state and local requirements. A number of our natural gas processing facilities are also subject to OSHA’s process safety management regulations and the Environmental Protection Agency’s (“EPA”) risk management plan requirements. Together these regulations are designed to prevent or minimize the probability and consequences of an accidental

release of toxic, reactive, flammable or explosive chemicals. A number of our facilities are also regulated under the U.S. Department of Homeland Security Chemical Facility Anti-Terrorism Standards (“Homeland Standards”), which are designed to regulate the security of high-risk chemical facilities. Our natural gas processing plants and operations are operated in a manner consistent with industry safe practices and standards.

TERMINAL SAFETY. Our operations are subject to regulations under OSHA and comparable state and local regulations. Our terminal facilities are operated in a manner consistent with industry safe practices and standards. The storage tanks that are at our terminals are designed for crude oil and refined products and are equipped with appropriate controls that minimize emissions and promote safety. Our terminal facilities have response and control plans, spill prevention and other programs to respond to emergencies. Our terminals are regulated under the Homeland Standards or U.S. Coast Guard Maritime Transportation Act, which are designed to regulate the security of high–risk chemical facilities.

RAIL SAFETY. Our rail operations are limited to loading and unloading rail cars at our facilities. Generally, rail operations are subject to federal, state and local regulations. We believe our rail car loading and unloading operations meet or exceed all applicable regulations.

RATE AND OTHER REGULATIONS

GENERAL INTERSTATE REGULATION. Our High Plains Pipeline, Northwest Products Pipeline and two other interstate pipelines are common carriers subject to regulation by various federal, state and local agencies. The Federal Energy Regulatory Commission (“FERC”) regulates interstate transportation on our crude oil transportation and gathering pipelines and Northwest Products Pipeline under the Interstate Commerce Act (“ICA”), the Energy Policy Act of 1992 (the “EPAct”), and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on oil pipelines, including interstate pipelines that transport crude oil and refined products (collectively, “Petroleum Pipelines”), be just and reasonable and non-discriminatory, and that we file such rates and terms and conditions of service with the FERC. Under the ICA, shippers may challenge new or existing rates or services. The FERC is authorized to suspend the effectiveness of a challenged rate for up to seven months, though rates are typically not suspended for the maximum allowable period. A successful rate challenge could result in Petroleum Pipelines paying refunds for the period that the rate was in effect and/or reparations for up to two years prior to the filing of a complaint. There are no pending challenges or complaints regarding our current tariffs.



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Certain interstate Petroleum Pipeline rates in effect at the inception of the EPAct are deemed to be just and reasonable under the ICA. These rates are referred to as grandfathered rates. Our rates for interstate transportation service on the Northwest Products Pipeline are grandfathered. The FERC allows for an annual rate change under its indexing methodology, which applies to transportation on our High Plains Pipeline and Northwest Products Pipeline.

We own a natural gas pipeline in Wyoming. Under the Natural Gas Act of 1938 (the “NGA”), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Federal regulation of interstate pipelines extends to such matters as rates, services, and terms and conditions of service; the types of services offered to customers; the certification and construction of new facilities; the acquisition, extension, disposition or abandonment of facilities; the maintenance of accounts and records; relationships between affiliated companies involved in certain aspects of the natural gas business; the initiation and continuation of services; market manipulation in connection with interstate sales, purchases or transportation of natural gas; and participation by interstate pipelines in cash management arrangements. The FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. Under the NGA, the rates for service on interstate facilities must be just and reasonable and not unduly discriminatory. The FERC has granted the Rendezvous Pipeline market-based rate authority, subject to certain reporting requirements. If the FERC were to suspend Rendezvous Pipeline’s market-based rate authority, it could have an adverse impact on our revenue associated with the transportation service.

INTRASTATE REGULATION. The intrastate operations of our High Plains Pipeline in North Dakota and our refined products pipeline in Alaska are subject to regulation by the North Dakota Public Service Commission (“NDPSC”) and the Regulatory Commission of Alaska, respectively. Applicable state law requires that:


•	pipelines operate as common carriers;


•	access to transportation services and pipeline rates be non-discriminatory;


•	transported crude oil volumes be apportioned without unreasonable discrimination if more crude oil is offered for transportation than can be transported immediately; and


•	pipeline rates be just and reasonable.

PIPELINES. We operate our crude oil gathering pipelines and the Northwest Products Pipeline as common carriers pursuant to tariffs filed with the FERC, and the NDPSC for the High Plains Pipeline. The High Plains Pipeline offers tariffs from various locations in Montana and North Dakota to a

variety of destinations, which are utilized by Tesoro and various third parties. Tesoro has historically shipped the majority of the volumes transported on the High Plains Pipeline, which is expected to continue in 2017. The Northwest Products Pipeline extends from Salt Lake City, Utah to Spokane, Washington and offers tariffs from various locations to a variety of destinations, which serves both third-party customers and Tesoro. We have additional pipelines that provide gathering of condensate in Wyoming and other pipelines that provide crude oil gathering in North Dakota.

The FERC and state regulatory agencies generally have not investigated rates on their own initiative absent a protest or a complaint by a shipper. Tesoro has agreed not to contest our tariff rates for the term of our commercial agreements. However, our pipelines are common carrier pipelines, and we may be required to accept additional third-party shippers who wish to transport through our system. The FERC or the NDPSC could investigate our rates at any time. If an interstate rate for service on the High Plains Pipeline or Northwest Products Pipeline were investigated, the challenger would have to establish that there has been a substantial change since the enactment of the EPAct, in either the economic circumstances or the nature of the service that formed the basis for the rate. If our rates are investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs.

Section 1(b) of the NGA exempts natural gas gathering facilities from the FERC’s jurisdiction. Although the FERC has not made formal determinations with respect to all of the facilities we consider to be gathering facilities, we believe that our natural gas pipelines meet the FERC’s traditional tests to determine that they are gathering pipelines and are, therefore, not subject to FERC jurisdiction.

States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based regulation. Our natural gas and crude oil gathering operations are subject to ratable take and common purchaser statutes in most of the states in which we operate. These statutes generally require our gathering pipelines to take natural gas or crude oil without undue discrimination as to source of supply or producer. The regulations under these statutes can have the effect of imposing some restrictions on our ability as an owner of gathering facilities to decide with whom we contract to gather natural gas or crude oil. Failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies. To date, there has been no adverse effect to our systems due to these regulations.

ENVIRONMENTAL REGULATIONS

GENERAL. Our operations of pipelines, terminals and associated facilities in connection with the storage and



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BUSINESS

transportation of crude oil, refined products and biofuels as well as our operations of gathering, processing and associated facilities related to the movement of natural gas are subject to extensive and frequently-changing federal, state and local laws, regulations, permits 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, liquid, salt water and hazardous wastes and the remediation of contamination. 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. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment. These requirements may also significantly affect our customers’ operations and may have an indirect effect on our business, financial condition and results of operations. However, we do not expect such effects will have a material impact on our financial position, results of operations or liquidity.

Under the Third Amended and Restated Omnibus Agreement (“Amended Omnibus Agreement”) and the Carson Assets Indemnity Agreement, Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and the subsequent Acquisitions from Tesoro. See Note 10 to our consolidated financial statements in Part II, Item 8 for additional information regarding the Amended Omnibus Agreement and Carson Assets Indemnity Agreement.

AIR EMISSIONS AND CLIMATE CHANGE REGULATIONS. Our operations are subject to the Clean Air Act and comparable state and local statutes. 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. If regulations become more stringent, additional emission control technologies may be required to be installed at our facilities and our ability to secure future permits may become less certain. Any such future obligations could require us to incur significant additional capital or operating costs.

The EPA has undertaken significant regulatory initiatives under authority of the Clean Air Act’s New Source Review/Prevention of Significant Deterioration program (“NSR/

PSD”) in an effort to further reduce emissions of volatile organic compounds, nitrogen oxides, sulfur dioxide, and particulate matter. These regulatory initiatives have been targeted at industries with large manufacturing facilities that are significant sources of emissions, such as refining, paper and pulp, and electric power generating industries. The basic premise of these initiatives is the EPA’s assertion that many of these industrial establishments have modified or expanded their operations over time without complying with NSR/PSD regulations adopted by the EPA that require permits and new emission controls in connection with any significant facility modifications or expansions that can result in emission increases above certain thresholds. As part of this ongoing NSR/PSD regulatory initiative, the EPA has entered into consent decrees with several refiners, including Tesoro, that require the refiners to make significant capital expenditures to install emissions control equipment at selected facilities. However, we do not expect any additional requirements will have a material impact on our financial position, results of operations or liquidity.

On October 1, 2015, EPA strengthened the National Ambient Air Quality Standards (“NAAQS”) for ground-level ozone to 70 parts per billion (“ppb”) from the 75 ppb level set in 2008. To implement the revised ozone NAAQS, all states will need to review their existing air quality management infrastructure State Implementation Plan for ozone and ensure it is appropriate and adequate. Where areas remain in ozone non-attainment, or come into ozone non-attainment as a result of the revised NAAQS it is likely that additional planning and control obligations will be required. States may impose additional emissions control requirements on stationary sources, changes in fuels specifications, and changes in fuels mix and mobile source emissions controls. The ongoing and potential future requirements imposed by states to meet the ozone NAAQS could have direct impacts on Tesoro facilities through additional requirements and increased permitting costs, and could have indirect impacts through changing or decreasing fuel demand.

The Energy Independence and Security Act was enacted into federal law in December 2007 creating a second Renewable Fuels Standard (“RFS2”) requiring the total volume of renewable transportation fuels (including ethanol and advanced biofuels) sold or introduced in the U.S. to reach 36.0 billion gallons by 2022. On December 14, 2015, the EPA issued a final rule establishing the Renewable Fuel Standard requirements for 2014 (16.28 billion gallons), 2015 (16.93 billion gallons) and 2016 (18.11 billion gallons). The ongoing and increasing requirements for renewable fuels in RFS2 could reduce future demand for petroleum products and thereby have an indirect effect on certain aspects of our business, although it could increase demand for our ethanol and biodiesel fuel blending services at our truck loading racks.

Currently, multiple legislative and regulatory measures to address greenhouse gas emissions are in various phases



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of discussion or implementation. These include actions to develop national, state or regional programs, each of which could require reductions in our greenhouse gas emissions or those of Tesoro and our other customers. On October 22, 2015, the EPA finalized amendments to the Petroleum and Natural Gas Systems source category (Subpart W) of the Greenhouse Gas Reporting Program, including adding a new Onshore Petroleum and Natural Gas Gathering and Boosting segment, which will include greenhouse gas emissions from equipment and sources within the petroleum and natural gas gathering and boosting systems. In September 2015, the EPA announced proposed new source performance standards for methane (a greenhouse gas) for new and modified oil and gas sector sources. These and other legislative regulatory measures will impose additional burdens on our business and those of Tesoro and our other customers.

HAZARDOUS SUBSTANCES AND WASTE REGULATIONS. 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. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), 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 owner or operator of the site where the release occurred and companies that disposed of, or arranged for the disposal 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. 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. Costs for these remedial actions, if any, as well as any related claims are all covered by indemnities from Tesoro to the extent the release occurred or existed before the close of the Initial Offering and subsequent Acquisitions from Tesoro. Neither the Partnership nor Tesoro are currently engaged in any CERCLA related claims.

We also generate solid and liquid 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, including wastes generated from the transportation and storage of crude oil, natural gas, NGLs and refined products. We are not currently required to comply with a substantial portion of the RCRA requirements because the majority of our facilities operate as small quantity generators of hazardous wastes by the EPA and state regulations. However, it is possible that additional wastes, which could include wastes currently generated during operations, will in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly disposal requirements than are non-hazardous wastes. On November 28, 2016, the EPA published the final Hazardous Waste Generator Improvements Rule. This rule provided some additional flexibility for small generators but also increased certain recordkeeping and administrative burdens. Any additional changes in the regulations could increase our capital or operating costs.

We acquired two salt water disposal wells located in North Dakota on January 1, 2017. These facilities are permitted under state regulations to accept produced water and fluids or waters from drilling and gas plant operations. These fluids are considered exempt from RCRA requirements per the Exploration & Production (“E&P”) exemption. Changes to state or federal regulations regarding the E&P exemption or rules for the operation of disposal wells could impose additional burdens on our business.

We currently own and lease properties where crude oil, refined petroleum hydrocarbons and fuel additives, such as methyl tertiary butyl ether and ethanol have been handled for many years by previous owners. At some facilities, hydrocarbons or other 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 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 other wastes was not under our control. These properties 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 or released wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including impacted groundwater), or to perform remedial operations to prevent future contamination to the extent we are not indemnified for such matters.

WATER POLLUTION REGULATIONS. Our operations can result in the discharge of pollutants, including chemical components of crude oil, natural gas, NGLs and refined products. Many of our facilities operate near environmentally sensitive waters, where tanker, pipeline and other petroleum product transportation operations are



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regulated by federal, state and local agencies and monitored by environmental interest groups. The transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions in some cases of the Oil Pollution Act of 1990 (“OPA 90”), and in all cases to related state requirements. These requirements can subject owners of covered facilities to strict, joint, and potentially unlimited liability for removal costs and other consequences of an oil spill where the spill is into navigable waters, along shorelines or in the exclusive economic zone of the United States. In the event of an oil spill into navigable waters, substantial liabilities could be imposed upon us. States in which we operate have also enacted similar, or in some cases, more stringent laws.

Regulations under the Water Pollution Control Act of 1972 (the “Clean Water Act”), OPA 90 and state laws also impose additional regulatory burdens on our operations. Spill prevention control and countermeasure requirements of federal laws and state laws require containment to mitigate or prevent contamination of waters in the event of a crude oil, natural gas, NGLs or refined products overflow, rupture, or leak from above-ground pipelines and storage tanks. The Clean Water Act requires us to maintain spill prevention control and countermeasure plans at our facilities with above-ground storage tanks and pipelines. In addition, OPA 90 requires that most oil transport and storage companies maintain and update various oil spill prevention and oil spill contingency plans. We maintain such plans, and where required have submitted plans and received federal and state approvals necessary to comply with OPA 90, the Clean Water Act and related regulations. Our crude oil, natural gas, NGLs and refined product spill prevention plans and procedures are frequently reviewed and modified to prevent crude oil, natural gas, NGLs and refined product releases and to minimize potential impacts should a release occur. At our facilities adjacent to water, federally certified Oil Spill Response Organizations (“OSROs”) are available to respond to a spill on water from above ground storage tanks or pipelines. We have contracts in place to ensure support from the respective OSROs for spills in both open and inland waters.

The OSROs are capable of responding to a spill on water equal to the greatest volume of the largest above ground storage tank at our facilities. Those volumes range from 5,000 barrels to 125,000 barrels. The OSROs have the highest available rating and certification from the United States Coast Guard (“USCG”) and are required to annually demonstrate their response capability to the USCG and state agencies. The OSROs rated and certified to respond to open water spills (which include those OSROs with which we contract at our marine terminals that have received the highest available rating and certification from the USCG) must demonstrate the capability to recover up to 50,000 barrels of oil per day and store up to 100,000 barrels of recovered oil at any given time. The OSROs rated and certified to respond to inland spills must demonstrate the

capability to recover up to 7,500 barrels of oil per day and store up to 15,000 barrels of recovered oil at any given time.

At each of our facilities, we maintain spill-response capability to mitigate the impact of a spill from our facilities until either an OSRO or other contracted service providers can deploy, and Tesoro has entered into contracts with various parties to provide spill response services augmenting that capability, if required. Our spill response capability at our marine terminals meets the United States Coast Guard and state requirements to either deploy on-water containment equipment two times the length of a vessel at our dock or have smaller vessels available. Our spill response capabilities at our other facilities meet applicable federal and state requirements. In addition, we contract with various spill-response specialists to ensure appropriate expertise is available for such contingencies. We believe these contracts provide the additional services necessary to meet or exceed all regulatory spill-response requirements.

The Clean Water Act also imposes restrictions and strict controls regarding the discharge of pollutants into navigable waters. In certain locations, we contract with third parties for wastewater disposal. Our remaining facilities may have portions of their wastewater reclaimed by Tesoro’s nearby refineries. In the event regulatory requirements change, or interpretations of current requirements change, and our facilities are required to undertake different wastewater management arrangements, we could incur substantial additional costs. The Clean Water Act and RCRA can both impose substantial potential liability for the violation of permits or permitting requirements and for the costs of removal, remediation, and damages resulting from such discharges. In addition, states maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater.

TRIBAL LANDS. Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. For example, the EPA has established a preconstruction permitting program for new and modified minor sources throughout Indian country, and new and modified major sources in nonattainment areas in Indian country effective March 2016. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our natural gas gathering operations on such lands.

HYDRAULIC FRACTURING. We do not conduct hydraulic fracturing operations, but substantially all of our customers’



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natural gas and crude oil production requires hydraulic fracturing as part of the completion process. Hydraulic fracturing is an essential and common practice in the oil and natural gas industry used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The process is typically regulated by state oil and natural-gas commissions, but the EPA and other federal agencies have asserted federal regulatory authority over the process. For example, the EPA has announced its intent to propose standards for wastewater discharge from oil and gas extraction activities, and in May 2014 issued an Advanced Notice of Proposed Rulemaking seeking public comment on its plans to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing. In addition, the U.S. Department of the Interior published a revised proposed rule on May 16, 2013 that would implement updated requirements for hydraulic fracturing activities on federal lands, including new requirements relating to public disclosure, well bore integrity, and handling of flowback water.

If additional levels of regulation and permits are required through the adoption of new laws and regulations at the federal, state or local level that could lead to delays, increased operating costs and prohibitions for producers who drill near our pipelines, which could reduce the volumes of crude oil and natural gas available to move through our gathering systems and processing facilities, which could materially adversely affect our revenue and results of operations.

WORKING CAPITAL

We fund our business operations through a combination of available cash and equivalents and cash flows generated from operations. In addition, we have an available revolving line of credit and we may issue additional debt or equity securities for additional working capital or capital expenditures. See “Capital Resources and Liquidity” in Item 7 for additional information regarding working capital.

EMPLOYEES

All of the employees that conduct our business are employed by our general partner and its affiliates, and we believe that our general partner and its affiliates have a satisfactory relationship with those employees. TLGP had 1,088 employees performing services for our operations as of December 31, 2016, 204 of whom are covered by collective bargaining agreements that expire on February 1, 2019.

WEBSITE ACCESS TO REPORTS AND OTHER INFORMATION

Our Internet website address is http://www.tesorologistics.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, Current Reports on Form 8-K and other public filings with the Securities and Exchange Commission (“SEC”) are available, free of charge, on our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. You may also access these reports on the SEC’s website at http://www.sec.gov.



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MARKET FOR EQUITY, STOCKHOLDER MATTERS AND PURCHASES OF EQUITY SECURITIES

PART II

ITEM 6. SELECTED FINANCIAL DATA

The following table sets forth certain selected financial data as of and for each of the five years in the period ended December 31, 2016, which is derived from the combined financial results of Tesoro Logistics LP predecessor (the “TLLP Predecessor”), our predecessor for accounting purposes and the consolidated financial results of TLLP.

In 2016, 2015 and 2014, we entered into various transactions with Tesoro and our general partner, TLGP, pursuant to which TLLP acquired from Tesoro the following:


•	tankage, refined product storage, marine terminal terminalling and storage assets, pipelines, causeway and ancillary equipment located in Martinez, California, effective November 21, 2016;


•	all of the limited liability company interests in Tesoro Alaska Terminals, LLC, tankage, bulk tank farm, a truck rack and rail-loading facility, terminalling and other storage assets located in Kenai, Anchorage and Fairbanks, Alaska, completed in two stages on July 1, 2016 and September 16, 2016;


•	a crude oil and refined products storage tank facility located at Tesoro’s Los Angeles refinery and a 50% fee interest in a pipeline that transports jet fuel from Tesoro’s Los Angeles refinery to the Los Angeles International Airport, effective November 12, 2015; and


•	truck terminals, storage tanks, rail loading and unloading facilities and a refined products pipeline effective July 1, 2014, for the terminals, storage tanks and rail facilities and effective September 30, 2014, for the refined products pipeline (the “West Coast Logistics Assets Acquisition”).

These transactions are collectively referred to as “Acquisitions from Tesoro”.

These transactions were transfers between entities under common control. Accordingly, the financial information contained herein of the TLLP Predecessors and TLLP have been retrospectively adjusted to include the historical results of the Predecessors. Our Predecessors did not record revenue for intercompany trucking, terminalling, storage and short-haul pipeline transportation services.

All financial results have also been adjusted for subsequent transactions with Predecessors. For additional information regarding these adjustments, see “Business Strategy and Overview” and “Results of Operations” in Item 7.



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SELECTED FINANCIAL DATA

The following table should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 and our consolidated financial statements in Item 8.

SELECTED FINANCIAL DATA



	Years Ended December 31,
	2016 (a)		2015 (a)			2014 (a)			2013 (a)		2012 (a)
	(In millions, except units and per unit amounts)
Statement of Operations Data
Total revenues (b)	$	1,220	$	1,112		$	600		$	313	$	164
Net earnings	$	315	$	249		$	56		$	18	$	48
Loss attributable to Predecessors	24		43			46			62		9
Net earnings attributable to noncontrolling interest	—		(20		)	(3		)	—		—
Net earnings attributable to partners	$	339	$	272		$	99		$	80	$	57
General partner’s interest in net earnings, including incentive distribution rights	$	152	$	73		$	43		$	12	$	3
Common unitholders’ interest in net earnings	$	187	$	199		$	43		$	46	$	28
Subordinated unitholders’ interest in net earnings	$	—	$	—		$	13		$	22	$	26
Net earnings per limited partner unit:
Common - basic	$	1.87	$	2.33		$	0.96		$	1.48	$	1.90
Common - diluted	$	1.87	$	2.33		$	0.96		$	1.47	$	1.89
Subordinated - basic and diluted	$	—	$	—		$	0.62		$	1.35	$	1.47
Cash distribution per unit	$	3.3070	$	2.8350		$	2.4125		$	2.0175	$	1.6050

	As of December 31,
	2016		2015 (a)			2014 (a)			2013 (a)		2012 (a)
	(in millions)
Balance Sheet Data
Total assets	$	5,860	$	5,131		$	4,955		$	1,560	$	381
Total debt, net of unamortized issuance costs	$	4,054	$	2,844		$	2,544		$	1,141	$	344


(a)	Includes the historical results related to TLLP and Predecessors for years 2016, 2015 and 2014. For years 2013 and 2012, recasted amounts for the recent 2016 dropdowns are not shown because management does not believe presentation of these impacts is material to an investor’s understanding of TLLP’s current operations.

(b)

Our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment for assets acquired in the Acquisitions from Tesoro prior to the effective date of each acquisition, with the exception of transportation regulated by the FERC and the Regulatory Commission of Alaska tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Unless the context otherwise requires, references in this report to “Tesoro Logistics LP,” “TLLP,” “the Partnership,” “we,” “us” or “our” refer to Tesoro Logistics LP, one or more of its consolidated subsidiaries or all of them taken as a whole. Unless the context otherwise requires, references in this report to “Tesoro” refer collectively to Tesoro Corporation and any of its subsidiaries, other than TLLP, its subsidiaries and its general partner. Unless the context otherwise requires, references in this report to “Predecessors” refer collectively to the acquired assets from Tesoro, and those assets, liabilities and results of operations.

Management’s Discussion and Analysis is our analysis of our financial performance, financial condition and significant trends that may affect future performance. All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Important Information Regarding Forward-Looking Statements” for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business description, results of operations and financial condition should be read in conjunction with Items 1 and 2, and our consolidated financial statements and the notes thereto in Item 8.

BUSINESS STRATEGY AND OVERVIEW

We are committed to growing our fee-based revenue and diversifying our portfolio and being a leading full-service logistics company. In recent years, we have implemented organic and strategic investments to transform the composition of our portfolio. Refer to Part I, Item 1 for further discussion on our segments and the assets associated with our segments’ operations. See our Capital Expenditures discussion within the Capital Resources and Liquidity section for more on our organic growth strategy.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

STRATEGY AND GOALS

Our primary business objectives are to maintain and grow stable cash flows and to increase our quarterly cash distribution per unit over time. We intend to accomplish these objectives by executing the following strategies:



	Growing a stable, fee-based business that provides a competitive, full-service logistics offering to customers




	Optimizing Existing Asset Base		● Operating assets that are the safest, always compliant, highly reliable ● Improving operational efficiency and maximizing asset utilization ● Expanding third-party business; delivering extraordinary customer service




	Pursuing Organic Expansion Opportunities		● Identifying and executing low-risk, high-return growth projects ● Investing to capture the full commercial value of logistics assets ● Growing asset capability to support Tesoro value chain optimization




	Growing through Third Party Acquisitions		● Pursuing assets and businesses in strategic western U.S. geography that fit integrated business model, delivering synergies and growth ● Focusing on high quality assets that provide stable, fee-based income and enhancing organizational capacity




	Growing through Tesoro Strategic Expansion		● Strategically partnering with Tesoro on acquisitions in refining and marketing value chains ● Capturing full value of Tesoro’s embedded logistics assets

We have been implementing our strategy, which has allowed us to increase our distributions by 17% over last year. In addition, relative to these goals, in 2017, we intend to continue implementing this strategy and have completed or announced plans to:

•

expand our assets on our Gathering and Processing segment located in the Bakken Shale/Williston Basin area of North Dakota and Montana (the “Bakken Region”) and Green River Basin, Uinta Basin and Vermillion Basin in the states of Utah, Colorado and Wyoming (the “Rockies Region”) in support of third-party demand for crude oil, natural gas and water gathering services, natural gas gathering and associated gas processing services as well as serving Tesoro’s demand for Bakken crude oil in the mid-continent and west coast refining systems, including:


◦	further expanding capacity and capabilities as well as adding new origin and destination points for our common carrier pipelines in North Dakota and Montana (the “High Plains Pipeline”);


◦	expanding our crude oil, natural gas and water gathering and associated gas processing footprint in the Bakken Region to enhance and improve overall basin logistics efficiencies;


◦	increasing compression on our natural gas gathering systems in the Green River and Vermillion basins to enhance natural gas volumes recovered from existing wells and support potential new drilling activity;


◦	expanding our gathering footprint and increase compression capabilities in the Uinta basin to increase volumes on our gathering systems and through our processing assets; and


◦	pursuing strategic assets across the western U.S. including potential acquisitions from Tesoro.


•	grow our terminalling and transportation business across the western U.S. through:


◦	increasing our terminalling volumes by expanding capacity and growing our third-party services at certain of our terminals;


◦	optimizing Tesoro volumes and growing third-party throughput at our terminalling and transportation assets; and


◦	pursuing strategic assets in the western U.S. such as our acquisition of Tesoro’s terminalling assets and storage assets in Alaska and California.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

ACQUISITIONS

NORTH DAKOTA GATHERING AND PROCESSING ASSETS. On January 1, 2017, we acquired crude oil, natural gas and produced water gathering systems and two natural gas processing facilities from Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Energy Midstream, LLC for total consideration of approximately $700 million funded with cash on-hand, which included the borrowings under our secured revolving credit facility (the “Revolving Credit Facility”). The North Dakota Gathering and Processing Assets include over 650 miles of crude oil, natural gas, and produced water gathering pipelines, 170 MMcf per day of natural gas processing capacity and 18.7 thousand barrels per day (“Mbpd”) of fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. The revenue from the assets is approximately 90% fee-based and backed by acreage dedications from ten producers. The acquisition was announced on November 21, 2016 and was subject to customary closing conditions including regulatory approval.

NORTHERN CALIFORNIA TERMINALLING AND STORAGE ASSETS. Effective November 21, 2016, we acquired certain terminalling and storage assets located in Martinez, California from subsidiaries of Tesoro for a total consideration of $400 million, comprised of $360 million in cash financed with borrowings under our secured dropdown credit facility (the “Dropdown Credit Facility”), and the issuance of equity to Tesoro with a fair value of approximately $40 million. The Northern California Terminalling and Storage Assets include 5.8 million barrels of crude oil, feedstock, and refined product storage capacity at Tesoro’s Martinez Refinery along with the Avon marine terminal capable of handling up to 80 Mbpd of feedstock and refined product throughput. The equity consideration was comprised of common units and general partner units. In connection with the acquisition, we and Tesoro entered into long-term, fee-based storage and throughput and use agreements.

ALASKA STORAGE AND TERMINALLING ASSETS. Effective July 1, 2016, we agreed to purchase certain terminalling and storage assets owned by Tesoro for total consideration of $444 million, which was completed in two phases. On July 1, 2016, we completed the acquisition of the first phase consisting of tankage with a shell capacity of approximately 3.5 million barrels and ancillary facilities used for the operations at Tesoro’s Kenai Refinery. The second phase was completed on September 16, 2016 and consisted of refined product terminals in Anchorage and Fairbanks. Consideration paid for the first phase was $266 million, comprised of approximately $240 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of equity to Tesoro with a fair value of $26 million. Consideration paid for the second phase was $178 million, comprised of approximately $160 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of equity to Tesoro with a fair value of $18 million.

CURRENT MARKET DEVELOPMENTS

In 2016, the yearly average spot prices of the commodities that we handle, including crude oil, natural gas, and refined products, declined while prices for natural gas liquids increased. The lower price levels along with increased volatility in the commodity price environment created challenges for crude oil and natural gas producers who have reduced their drilling and production plans in the basins where we operate. The U.S. oil and gas drilling rig count continued to see declines in the first half of 2016 but reversed course in the second half of the year leaving year-over-year count relatively unchanged. Looking forward, price appreciation, improved producer economics, advanced drilling techniques, improved drilling efficiencies along with a backlog of uncompleted wells available for completion could positively impact overall U.S. production volumes.

Lower retail prices and favorable economic conditions throughout 2016 supported increased demand for refined products from our downstream refining and marketing customers. Changes in the U.S. political landscape, namely around the lifting of the 40 year old crude oil export ban in December 2015, had a minimal impact on our business and we believe this will continue to be the case in the short term. We continue to monitor the impact of these changes in market prices and fundamentals as it relates to our business. Currently, we believe our diversified portfolio, which is underpinned by long-term contracts, many of which are supported by minimum volume commitments, adequately supports our goals and objectives outlined above.

RESULTS OF OPERATIONS

A discussion and analysis of the factors contributing to our results of operations presented below includes the combined financial results of our Predecessors and the consolidated financial results of TLLP. The financial statements, together with the following information, are intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting future performance.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

HOW WE EVALUATE OUR OPERATIONS

Our management uses a variety of financial and operating measures to analyze operating segment performance. These measures are significant factors in assessing our operating results and profitability and include: (1) throughput volumes (including gas gathering and processing, crude oil and water gathering and terminalling), (2) operating expenses and (3) certain other financial measures as discussed further in “Non-GAAP Financial Measures” below, including net earnings before interest, income taxes, depreciation and amortization expenses (“EBITDA”) and Distributable Cash Flow.

Management utilizes the following operating metrics to evaluate performance and compare profitability to other companies in the industry:


•	Average margin on Natural Gas Liquids (“NGL”) sales per barrel—calculated as the difference between the NGL sales and the costs associated with the NGL sales divided by total NGL sales volumes;


•	Average gas gathering and processing revenue per Million British thermal units (“MMBtu”)—calculated as total gathering and processing fee-based revenue divided by total gas gathering throughput;


•	Average crude oil and water gathering revenue per barrel—calculated as total crude oil and water gathering fee-based revenue divided by total crude oil and water gathering throughput;


•	Average terminalling revenue per barrel—calculated as total terminalling revenue divided by total terminalling throughput; and


•	Average pipeline transportation revenue per barrel—calculated as total pipeline transportation revenue divided by total pipeline transportation throughput.

There are a variety of ways to calculate average revenue per barrel, average revenue per MMBtu and average keep-whole fee per barrel; other companies may calculate these in different ways.

THROUGHPUT VOLUMES. The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas, NGLs and refined products that we handle with our pipeline, trucking, terminalling and processing assets. These volumes are affected by the supply of, and demand for, crude oil, natural gas, NGLs and refined products in the markets served directly or indirectly by our assets. Although Tesoro and other third-party customers have committed to minimum volumes under commercial agreements, our results of operations will be impacted by our ability to:


•	increase throughput volumes on our common carrier crude oil gathering and transportation system in North Dakota and Montana (“High Plains System”) by making connections to existing or new third-party pipelines or rail loading facilities, which will be driven by the anticipated supply of and demand for additional crude oil produced from the Bakken Region;


•	increase throughput volumes at our refined products terminals and provide additional ancillary services at those terminals, such as ethanol blending and additive injection;


•	increase throughput volumes on our natural gas system through the connection of new wells and addition of compression to existing wells; and


•	identify and execute organic expansion projects, and capture incremental Tesoro or third-party volumes.

Additionally, increased throughput may depend on Tesoro transferring volumes that it currently distributes through competing terminals to our terminals, including certain terminals located in Washington and California.

OPERATING EXPENSES. We manage our operating expenses in tandem with meeting our environmental and safety requirements and objectives and maintaining the integrity of our assets. Our operating expenses are comprised primarily of labor expenses, repairs and other maintenance costs, lease costs and utility costs. With the exception of contract labor for trucking, additive costs at our terminals and utilities, transportation and fractionation fees, which vary based on throughput volume, our expenses generally remain stable across broad ranges of throughput volumes, but can fluctuate from period to period depending on the mix of activities performed during that period and the timing of those expenses. We seek to manage our maintenance expenditures on our pipelines and terminals by scheduling maintenance throughout the year, when possible, to avoid significant variability in our maintenance expenditures and minimize their impact on our cash flows.

Our operating expenses are also affected by the imbalance gain and loss provisions in our active published tariffs and in our commercial agreements with Tesoro. Under our contractual agreements or tariffs, we retain a portion of the crude oil shipped on certain of our pipelines or refined products we handle at certain of our terminals and bear any volume losses in excess of that retained amount. The value of any crude oil or refined product imbalance settlements resulting from these tariffs or contractual provisions is determined by using the average market prices for the applicable commodity, less a specified discount as specified in the agreement or tariff. Any settlements under tariffs or contractual provisions where we bear any crude oil or refined product volume losses less than amounts specified reduce our operating expenses in the period in which they are realized to the extent they are within the loss allowance and increase our operating expenses in such period to the extent they exceed the loss allowance.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

For other terminals, and under our other commercial agreements with Tesoro, we have no obligation to measure volume losses and have no liability for physical losses.

NON-GAAP FINANCIAL MEASURES

As a supplement to our financial information presented in accordance with accounting principles generally accepted in the United States of America (“U.S. GAAP”), our management uses certain “non-GAAP” measures to analyze our results of operations, assess internal performance against budgeted and forecasted amounts and evaluate future impacts to our financial performance as a result of capital investments, acquisitions, divestitures and other strategic projects. These measures are important factors in assessing our operating results and profitability and include:


•	Financial non-GAAP measure of EBITDA, as defined above; and


•	Liquidity non-GAAP measures:


◦	Distributable Cash Flow—U.S. GAAP-based net cash flow from operating activities plus or minus changes in working capital, amounts spent on maintenance capital net of reimbursements and other adjustments not expected to settle in cash


◦	Pro Forma Distributable Cash Flow—Distributable Cash Flow plus or minus adjustments for the acquisition of noncontrolling interest in connection with the merger of QEP Midstream Partners, LP (“QEPM”) with TLLP completed in July 2015

We present these measures because we believe they may help investors, analysts, lenders and ratings agencies analyze our results of operations and liquidity in conjunction with our U.S. GAAP results, including but not limited to:


•	our operating performance as compared to other publicly traded partnerships in the midstream energy industry, without regard to historical cost basis or financing methods;


•	the ability of our assets to generate sufficient cash flow to make distributions to our unitholders;


•	our ability to incur and service debt and fund capital expenditures; and


•	the viability of acquisitions and other capital expenditure projects and the returns on investment of various investment opportunities.

Management also uses these measures to assess internal performance, and we believe they may provide meaningful supplemental information to the users of our financial statements. Non-GAAP measures have important limitations as analytical tools, because they exclude some, but not all, items that affect net earnings, operating income and net cash from operating activities. These measures should not be considered substitutes for their most directly comparable U.S. GAAP financial measures.

FACTORS AFFECTING THE COMPARABILITY OF OUR FINANCIAL RESULTS

The Partnership’s future results of operations may not be comparable to the historical results of operations of the acquired assets from our Predecessors for the reasons described below.

Our financial information includes the historical results of our Predecessors and the results of TLLP for all periods presented. The financial statements of our Predecessors have been prepared from the separate records maintained by Tesoro and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity.

There are differences in the way our Predecessors recorded revenues and the way the Partnership records revenues after the Acquisitions from Tesoro, as defined in Note 1 to our consolidated financial statements in Item 8. The assets that we acquire from Tesoro have historically been a part of the integrated operations of Tesoro, and our Predecessors generally recognized only the costs and did not record revenue for transactions with Tesoro. Accordingly, the revenues in our Predecessors’ historical combined financial statements relate only to amounts received from third parties for these services and amounts received from Tesoro with respect to transportation regulated by the Regulatory Commission of Alaska (“RCA”).

The Partnership’s revenues are generated by third-party contracts and from commercial agreements we entered into with Tesoro, under which Tesoro pays us fees for gathering crude oil and distributing, transporting and storing crude oil and refined products. Additionally, in conjunction with the acquiring all of the limited liability company interests of QEP Field Services, LLC, (the “Rockies Natural Gas Business Acquisition”), we began processing natural gas for certain producers under keep-whole processing agreements and gathering and processing natural gas under fee-based contracts. At that time, we concurrently entered into a five-year agreement with Tesoro, which transfers the commodity risk exposure associated with these keep-whole processing



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MANAGEMENT’S DISCUSSION AND ANALYSIS

agreements from us to Tesoro. See Note 3 to our consolidated financial statements in Item 8 for additional information on our keep-whole agreement with Tesoro.

We have a 78% interest in Rendezvous Gas Services, L.L.C. (“RGS”), which owns and operates the infrastructure that transports gas from certain fields to several re-delivery points in southwestern Wyoming, including natural gas processing facilities that are owned by us or a third party. Prior to 2016, we consolidated RGS; however, upon the reassessment performed in conjunction with our adoption of the Accounting Standards Update 2015-02, “Amendments to the Consolidation Analysis”, as of January 1, 2016, we determined RGS represents a variable interest entity to us for which we are not the primary beneficiary resulting in the deconsolidation of RGS and the reporting of RGS as an equity method investment. RGS is reflected in our results of operations for the years ended December 31, 2015 and 2014.

CONSOLIDATED RESULTS

HIGHLIGHTS (in millions)



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MANAGEMENT’S DISCUSSION AND ANALYSIS

RECONCILIATION OF NET EARNINGS TO EBITDA (in millions)



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
Reconciliation of Net Earnings to EBITDA:
Net earnings	$	315		$	249		$	56
Depreciation and amortization expense	190			187			85
Interest and financing costs, net of capitalized interest	191			150			109
Income tax expense	—			1			—
EBITDA	$	696		$	587		$	250

Reconciliation of Net Cash from Operating Activities to Distributable Cash Flow and Pro Forma Distributable Cash Flow:
Net cash from operating activities (b)	$	498		$	436		$	165
Changes in assets and liabilities	44			19			(13		)
Predecessors’ impact	17			34			37
Maintenance capital expenditures (c)	(72		)	(54		)	(44		)
Reimbursement for maintenance capital expenditures (c)	28			9			7
Net earnings attributable to noncontrolling interest (d)	—			(18		)	(3		)
Other adjustments for noncontrolling interest (e)	—			(21		)	8
Adjustments for equity method investments (f)	2			(3		)	—
Gain (loss) on sales of assets, net of proceeds	8			(1		)	14
Other (g)	7			21			49
Distributable Cash Flow	532			422			220
Pro forma adjustment for acquisition of noncontrolling interest (h)	—			36			(1		)
Pro Forma Distributable Cash Flow	$	532		$	458		$	219


(a)	Includes the historical results related to the Partnership and Predecessors for the years ended December 31, 2016, 2015 and 2014.


(b)	During the second quarter of 2016, we revised our reconciliation of distributable cash flow and pro forma distributable cash flow by reconciling the liquidity measure from net cash from operating activities. There were no impacts to previously reported amounts as a result of this methodology change.


(c)	We adjust our reconciliation of distributable cash flows for maintenance capital expenditures, tank restoration costs and expenditures required to ensure the safety, reliability, integrity and regulatory compliance of our assets with an offset for any reimbursements received for such expenditures.


(d)	Excludes $2 million of undistributed QEPM earnings prior to the closing of the merger of QEPM with TLLP, as discussed further in Note 2 to our consolidated financial statements in Item 8, for the year ended December 31, 2015, that unitholders of QEPM were entitled to receive, but TLLP unitholders received as a result of the merger.


(e)	Adjustments represent cash distributions in excess of (or less than) our controlling interest in income and depreciation as well as other adjustments for depreciation and maintenance capital expenditures applicable to the noncontrolling interest obtained in the Rockies Natural Gas Business Acquisition.


(f)	We adjust net cash from operating activities to reflect cash distributions received from equity method investments attributed to the period reported for the purposes of calculating distributable cash flow.

(g)

Other includes items that had a non-cash impact on our operations and should not be considered in distributable cash flow. Non-cash items primarily include the exclusion of the non-cash gain of $6 million recognized relating to the settlement of the Questar Gas Company litigation for the year ended December 31, 2016 and the inclusion of $13 million for acquired deficiency revenue billings to customers for the year ended December 31, 2015. Non-cash items for the year ended December 31, 2014 primarily include $19 million of acquisition costs included in general and administrative expenses primarily related to the merger of QEPM into TLLP, $10 million for acquired deficiency revenue billings to customers, $7 million of costs for detailed inspection and maintenance program on the Northwest Products System and a gain of $5 million from TLLP’s sale of its Boise terminal.


(h)	Reflects the adjustment to include the noncontrolling interest in QEPM as controlling interest based on the pro forma assumption that the merger occurred on December 2, 2014.

2016 COMPARED TO 2015

OVERVIEW. Our net earnings for 2016 increased $66 million, or 26.5%, to $315 million from $249 million for 2015 primarily driven by an increase in revenues partially offset by an increase to interest and financing costs. EBITDA increased $109 million corresponding with the $108 million increase to revenues as increases to operating expenses were offset by decreases in our general and administrative expenses.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

REVENUES. Revenues for 2016 increased $108 million, or 9.7%, to $1.2 billion benefiting from a full year of operations of the crude oil and refined product storage and pipeline assets in Los Angeles, California (the "LA Storage and Handling Assets")that were purchased from Tesoro in November 2015 and the 2016 acquisition of the Alaska Storage and Terminalling Assets that were purchased from Tesoro in July and September 2016. Terminalling and Transportation segment revenues increased $110 million as a result of the commercial storage agreements executed with Tesoro in connection with the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets. Revenues in our Gathering and Processing segment remained flat compared to 2015.

OPERATING AND OTHER EXPENSES. Operating expenses increased $14 million primarily due to the impact of deconsolidation of RGS in 2016 where transactions are reported gross. The related transactions with RGS in 2015 were eliminated during consolidation. Partially offsetting the increase was a decline in expenses recognized in connection with our environmental accruals.

INTEREST AND FINANCING COSTS. Net interest and financing costs increased $41 million primarily related to the issuance of new senior notes during 2016 and the write-off of unamortized debt issuance costs in connection with debt transactions as discussed in the “Capital Resources and Liquidity” section.

OTHER INCOME, NET. Other income, net for 2016 increased $6 million due to a one-time settlement gain. There were no settlement gains in 2015.

2015 COMPARED TO 2014

OVERVIEW. Our net earnings for 2015 increased $193 million, or 345%, to $249 million from $56 million for 2014 primarily driven by an increase in revenues. EBITDA increased $337 million primarily driven by the $512 million increase to revenues during the period partially offset by increases to operating and other expenses as a result of acquired operations.

REVENUES. Revenues for 2015 increased by $512 million, or 85%, to $1.1 billion driven primarily by the Rockies Natural Gas Business Acquisition and the West Coast Logistics Assets Acquisition. Revenues in our Gathering and Processing segment increased $459 million benefiting from a full year of operations of the Rockies Natural Gas Business. Terminalling and Transportation segment revenues increased $53 million due primarily to the West Coast Logistics Assets that were acquired mid-year in 2014.

OPERATING AND OTHER EXPENSES. The increase in revenues as a result of acquisitions was partially offset by a corresponding increase in expenses primarily due to a full year of operations of the Rockies Natural Gas Business acquired in December 2014. Excluding the impact of acquisitions, operating expenses were relatively flat, general and administrative expenses increased due to higher labor costs due to increased personnel headcount. Depreciation and amortization expenses increased due to acquisitions and organic growth projects being completed and placed into service including the Connolly Gathering System.

INTEREST AND FINANCING COSTS. Net interest and financing costs increased $41 million primarily due to the issuance of senior notes that were used to fund the Rockies Natural Gas Business Acquisition.

SEGMENT RESULTS OF OPERATIONS

GATHERING AND PROCESSING SEGMENT

HIGHLIGHTS



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MANAGEMENT’S DISCUSSION AND ANALYSIS

Our Gathering and Processing segment consists of crude oil, natural gas and produced water gathering systems in the Bakken Region and Rockies Region as well as gas processing complexes and fractionation facilities. Our High Plains System, located in the Bakken Region, gathers and transports crude oil from various production locations in this area for transportation to Tesoro’s Mandan refinery and other destinations in the Bakken Region, including export rail terminals and pipelines. Our natural gas gathering systems include the Uinta Basin Gathering System and our equity method investment Uintah Basin Field Services, L.L.C. In addition, we own four gathering systems and two pipelines regulated by the Federal Energy Regulatory Commission through, which we provide natural gas and crude oil transportation services. Our gas processing complexes consist of the Vermillion processing complex, the Uinta Basin processing complex, the Blacks Fork processing complex and the Emigrant Trail processing complex. Approximately 45-50% of our plant production is currently supported by long-term, fee-based processing agreements with minimum volume commitments



		December 31, 2016 \| 27



MANAGEMENT’S DISCUSSION AND ANALYSIS

GATHERING AND PROCESSING SEGMENT OPERATINGS RESULTS (in millions, except volumes, revenue per barrel and revenue per MMBtu amounts)



	Years Ended December 31,
	2016		2015
Revenues
NGL sales	$	103	$	99
Gas gathering and processing	264		274
Crude oil and water gathering	133		123
Pass-thru and other revenue	115		121
Total Revenues	615		617
Costs and Expenses
Cost of NGL sales	2		—
Operating expenses (a)	249		244
General and administrative expenses	36		44
Depreciation and amortization expenses	107		111
Loss on asset disposals and impairments	3		1
Gathering Segment Operating Income	$	218	$	217
Volumes/Rates
NGL sales (Mbpd)	7.5		7.9
Average margin on NGL sales per barrel	$	36.59	$	34.38
Gas gathering and processing throughput (thousands of MMBtu/d)	879		1,077
Average gas gathering and processing revenue per MMBtu	$	0.82	$	0.69
Crude oil and water gathering volume (Mbpd)	212		188
Average crude oil and water gathering revenue per barrel	$	1.72	$	1.79

2016 COMPARED TO 2015

VOLUMES. NGLs sales decreased 0.4 Mbpd, or 5%, to 7.5 Mbpd for 2016. Average gas gathering and processing volumes decreased 198 million British thermal units per day (“MMBtu/d”) in 2016 compared to 2015 driven primarily by the exclusion of volumes associated with RGS following its deconsolidation in 2016. Third-party volumes associate with RGS, which are included for 2015, were 141 thousand MMBtu/d. Crude oil and water gathering volumes increased 24 Mbpd, or 13%, in 2016, as a result of projects to expand the pipeline gathering system capabilities, which include additional origin and destination interconnections.

FINANCIAL RESULTS. Gathering and Processing segment revenues remained flat in 2016 compared to 2015. During 2016, revenues on the High Plains Pipeline System increased from 2015 were partially offset by decreases in gas gathering and processing revenues in 2016 as compared to 2015, which were primarily driven by the exclusion of volumes associated with RGS following our deconsolidation of RGS in 2016 partially offset by increases in the average gas gathering and processing rate recognized.

Operating expenses increased $5 million, or 2%, to $249 million in 2016 compared to $244 million in 2015, primarily related to the reporting of gross operating expense related to our transactions with RGS for 2016 that were previously eliminated in 2015 partially offset by lower environmental remediation costs.


(a)	Operating expenses include net imbalance settlement gains of $3 million, $2 million and $7 million in the years ended December 31, 2016, 2015 and 2014, respectively.

(b)

Prior to deconsolidation of RGS as of January 1, 2016, fees paid by TLLP to RGS were eliminated upon consolidation and third-party transactions, including revenue and throughput volumes, were included in TLLP’s results of operations. Third party volumes associated with RGS, included in gas gathering volume for the years ended December 31, 2015 and 2014, were 141 thousand MMBtu/d and 148 thousand MMBtu/d, respectively and reduced our average gas gathering revenue by approximately $0.05 per MMBtu for both periods.


(c)	We commenced natural gas gathering and processing operations with the acquisition of the Rockies Natural Gas Business in December 2014.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

GATHERING AND PROCESSING SEGMENT OPERATING RESULTS (in millions, except volumes, revenue per barrel and revenue per MMBtu amounts)



	Years Ended December 31,
	2015		2014 (c)
Revenues
NGL sales	$	99	$	7
Gas gathering and processing	274		17
Crude oil and water gathering	123		66
Pass-thru and other revenue	121		68
Total Revenues	617		158
Costs and Expenses
Operating expenses (a)	244		84
General and administrative expenses	44		10
Depreciation and amortization expenses	111		15
Loss on asset disposals	1		—
Gathering Segment Operating Income	$	217	$	49
Volumes/Rates
NGL sales (Mbpd)	7.9		6.5
Average margin on NGL sales per barrel	$	34.38	$	35.51
Gas gathering and processing throughput (thousands of MMBtu/d)	1,077		1,046
Average gas gathering and processing revenue per MMBtu	$	0.69	$	0.54
Crude oil and water gathering volume (Mbpd)	188		123
Average crude oil and water gathering revenue per barrel	$	1.79	$	1.46

2015 COMPARED TO 2014

VOLUMES. NGL sales volumes were 7.9 Mbpd in 2015, which contributed approximately 16% of total Gathering and Processing segment revenue as a result of increased processing utilization of our complexes. The 2014 results only included one month of activity and thus does not reflect seasonality or other market impacts. Gas gathering and processing throughput volumes increased 31 thousand MMBtu/d, or 3%, in 2015 primarily due to the addition of the natural gas gathering and processing operations with the Rockies Natural Gas Assets. Crude oil and water gathering throughput volumes increased 65 Mbpd, or 53%, in 2015 as a result of the expansion of our High Plains System and the acquisition of the crude oil gathering assets included in the Rockies Natural Gas Business acquired in December 2014. This increase was almost entirely due to third-party volumes.

FINANCIAL RESULTS. Gathering and Processing segment revenues increased $459 million, or 291%, to $617 million in 2015 compared to $158 million in 2014 primarily due to the addition of natural gas gathering and processing operations with the Rockies Natural Gas Assets as well as higher crude oil pipeline throughput on our High Plains Pipeline.

Operating expenses increased $160 million, or 190%, to $244 million in 2015 compared to $84 million in 2014, primarily due to a full year of operations from the Rockies Natural Gas Assets as well as the increased throughput on the High Plains System. The increase also includes an incremental expense of $6 million as compared to 2014 attributable to an accrual related to the remediation of the release of crude oil in a rural field northeast of Tioga, North Dakota that occurred in 2013 (the “Crude Oil Pipeline Release”).

Depreciation and amortization expense increased $96 million, or 640%, to $111 million in 2015 compared to $15 million in 2014 primarily due to the Rockies Natural Gas Assets having an entire year of depreciation and amortization as well as growth projects being placed into service including the Connolly Gathering System.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

TERMINALLING AND TRANSPORTATION SEGMENT

HIGHLIGHTS

Our Terminalling and Transportation segment consists of the Northwest Products Pipeline, which includes a regulated common carrier products pipeline running from Salt Lake City, Utah to Spokane, Washington and a jet fuel pipeline to the Salt Lake City International Airport; a regulated common carrier refined products pipeline system connecting Tesoro’s Kenai refinery to Anchorage, Alaska; and crude oil and refined products terminals and storage facilities in the western and midwestern U.S.; marine terminals in California; a rail-car unloading facility in Washington; a petroleum coke handling and storage facility in Los Angeles; and other pipelines, which transport products and crude oil from Tesoro’s refineries to nearby facilities in Salt Lake City and Los Angeles.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

TERMINALLING AND TRANSPORTATION SEGMENT OPERATING RESULTS (in millions, except barrel and per barrel amounts)



	Years Ended December 31,
	2016(a)		2015(a)		2014(a)
Revenues
Terminalling revenues	$	480	$	377	$	333
Pipeline transportation revenues	125		118		109
Total Revenues	605		495		442
Costs and Expenses
Operating expenses (b)	193		184		197
General and administrative expenses	32		32		30
Depreciation and amortization expenses	83		76		70
Loss (gain) on asset disposals and impairments	1		—		(4		)
Terminalling and Transportation Segment Operating Income	$	296	$	203	$	149
Volumes/Rates
Terminalling throughput (Mbpd)	984		955		952
Average terminalling revenue per barrel	$	1.33	$	1.08	$	0.96
Pipeline transportation throughput (Mbpd)	868		825		822
Average pipeline transportation revenue per barrel	$	0.39	$	0.39	$	0.36

2016 COMPARED TO 2015

VOLUMES. Terminalling throughput increased 29 Mbpd, or 3% and pipeline transportation throughput increased 43 Mbpd, or 5% in 2016 compared to 2015 primarily as a result of stronger customer demand, terminalling assets from the Alaska Storage and Terminalling Assets acquisition and organic growth projects adding new capabilities to our system.

FINANCIAL RESULTS. Revenues increased $110 million, or 22%, to $605 million in 2016 compared to $495 million in 2015 primarily as a result of the commercial storage agreements executed with Tesoro in connection with the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets, as well as increased throughput volumes. The increase in revenues was partially offset by a slight increase in operating expenses of $9 million, or 5%, to $193 million in 2016 compared to $184 million in 2015 as a result of the higher throughput volumes.

2015 COMPARED TO 2014

VOLUMES. Terminalling throughput increased 3 Mbpd in 2015 compared to 2014 primarily as a result of higher volumes at our southern California terminals and the completion of the Anacortes Light Products Truck Rack, which was partially offset by lower volumes at our Salt Lake City terminal. Pipeline transportation throughput increased 3 Mbpd in 2015 compared to 2014 primarily due to increased utilization of the southern California transportation pipeline system and performance enhancements.

FINANCIAL RESULTS. Revenues increased $53 million, or 12%, to $495 million in 2015 compared to $442 million in 2014 primarily as a result of the higher volumes at our southern California terminals and the commercial agreements executed with Tesoro at the time of the West Coast Logistics Assets Acquisition. Operating expenses decreased $13 million, or 7%, to $184 million in 2015 compared to $197 million in 2014 primarily as a result of enhanced operational efficiency and asset utilization.


(a)	Our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment for Predecessors’ assets acquired in the Acquisitions from Tesoro prior to the effective date of each acquisition, except for the RCA tariffs charged to Tesoro on the refined products pipeline included in the acquisition of the West Coast Logistics Assets.


(b)	Operating expenses include net imbalance settlement gains of $3 million, $4 million and $10 million in the years ended December 31, 2016, 2015 and 2014, respectively.



		December 31, 2016 \| 31



MANAGEMENT’S DISCUSSION AND ANALYSIS

CAPITAL RESOURCES AND LIQUIDITY

Our primary cash requirements relate to funding capital expenditures, meeting operational needs and paying distributions to our unitholders. We expect our ongoing sources of liquidity to include cash generated from operations, reimbursement for certain maintenance and expansion expenditures, borrowings under the Revolving Credit Facility and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital, long-term capital expenditure, acquisition and debt servicing requirements and allow us to fund at least the minimum quarterly cash distributions.

EQUITY OVERVIEW

Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders’ capital accounts based on their ownership interest at the time of issuance.

ATM PROGRAMS. On June 25, 2014, we filed a prospectus supplement to our shelf registration statement filed with the Securities and Exchange Commission (“SEC”) in 2012, authorizing the continuous issuance of up to an aggregate of $200 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “2014 ATM Program”). The 2014 ATM Program expired during the second quarter of 2015. For the year ended December 31, 2014 , we issued 199,400 common units for net proceeds of approximately $14 million. During the year ended December 31, 2015, we issued an aggregate of 819,513 common units under our 2014 ATM Program, generating proceeds of approximately $46 million before issuance costs. The net proceeds from sales under the 2014 ATM Program were used for general partnership purposes, which included debt repayment, future acquisitions, capital expenditures and additions to working capital.

On August 24, 2015, we filed a prospectus supplement to our shelf registration statement filed with the SEC on August 6, 2015, authorizing the continuous issuance of up to an aggregate of $750 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “2015 ATM Program”). During the years ended December 31, 2016 and 2015, we issued an aggregate of 1,492,637 and 1,093,483 common units, respectively, under our 2015 ATM Program, generating proceeds of approximately $72 million and $57 million, respectively, before issuance costs. The net proceeds from sales under the 2015 ATM Program were used for general partnership purposes, which included debt repayment, future acquisitions, capital expenditures and additions to working capital.

We paid fees of approximately $1 million related to the issuance of units under these programs for the year ended December 31, 2016.

DISTRIBUTIONS

Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the limited partner unitholders and general partner will receive. In connection with the North Dakota Gathering and Processing Assets acquisition, our general partner agreed to ratably reduce its quarterly distributions with respect to incentive distribution rights by $100 million with respect to distributions during 2017 and 2018.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

QUARTERLY DISTRIBUTIONS



Quarter Ended	Total Quarterly Distribution Per Unit		Total Quarterly Distribution Per Unit, Annualized		Total Cash Distribution (in millions)		Date of Distribution
December 31, 2016	$	0.9100	$	3.64	$	140	February 14, 2017
September 30, 2016	0.8750		3.50		131		November 14, 2016
June 30, 2016	0.8420		3.37		123		August 12, 2016
March 31, 2016	0.8100		3.24		108		May 13, 2016
December 31, 2015	0.7800		3.12		98		February 12, 2016
September 30, 2015	0.7500		3.00		86		November 13, 2015
June 30, 2015	0.7225		2.89		81		August 14, 2015
March 31, 2015	0.6950		2.78		70		May 15, 2015

We intend to pay a minimum quarterly distribution of at least $0.3375 per unit per quarter, which equates to approximately $35 million per quarter, or $142 million per year, based on the number of common and general partner units outstanding as of December 31, 2016. We do not have a legal obligation to pay this distribution.

DEBT OVERVIEW

TOTAL DEBT



	December 31,
Debt, including current maturities:	2016			2015
Revolving Credit Facility	$	330		$	305
Dropdown Credit Facility	—			—
TLLP Term Loan	—			250
5.500% Senior Notes due 2019	500			500
5.875% Senior Notes due 2020 (a)	470			470
6.125% Senior Notes due 2021 (a)	800			550
6.250% Senior Notes due 2022	800			800
6.375% Senior Notes due 2024	450			—
5.250% Senior Notes due 2025	750			—
Capital lease obligations and other	9			8
Total Debt	4,109			2,883
Unamortized Issuance Costs (a)	(55		)	(39		)
Debt, Net of Unamortized Issuance Costs	$	4,054		$	2,844


(a)	Unamortized premiums of $4 million associated with these senior notes are included in unamortized issuance costs at both December 31, 2016 and 2015.



		December 31, 2016 \| 33



MANAGEMENT’S DISCUSSION AND ANALYSIS

SENIOR NOTES BY MATURITY (in millions)

CREDIT FACILITIES

Based upon the guidelines of our current Revolving Credit Facility, we have the option to elect if the borrowings will bear interest at either, a base rate plus the base rate margin or a Eurodollar rate, for the applicable period, plus the Eurodollar margin at the time of the borrowing. The weighted average interest rate for borrowings under our Revolving Credit Facility was 2.76% at December 31, 2016. The Revolving Credit Facility is scheduled to mature on January 29, 2021.

EXPENSES AND FEES OF OUR CREDIT FACILITIES



Credit Facility	30 day Eurodollar (LIBOR) Rate at December 31, 2016	Eurodollar Margin	Base Rate	Base Rate Margin	Commitment Fee (unused portion)
Revolving Credit Facility (a)	0.77%	2.00%	3.75%	1.00%	0.375%
Dropdown Credit Facility (a)	0.77%	2.01%	3.75%	1.01%	0.375%

(a)

We have the option to elect if the borrowings will bear interest at either a base rate pus the base rate margin, or a Eurodollar rate, for the applicable period, plus the Eurodollar margin of the borrowing. The applicable margin varies based upon a certain leverage ratio, as defined by the Revolving Credit Facility. We also incur commitment fees for the unused portion of the Revolving Credit Facility at an annual rate. Letters of credit outstanding under the Revolving Credit Facility incur fees at the Eurodollar margin rate.

On January 29, 2016, we amended our existing secured Revolving Credit Facility. As a result of the amendment, we decreased the aggregate available facility limit from $900 million to $600 million and improved terms relating to pricing and financial covenants. Additionally on January 29, 2016, we syndicated the new $1.0 billion Dropdown Credit Facility. This facility provides us a flexible capital structure with a segregated source of financing for future asset acquisitions including transactions with Tesoro. The primary use of proceeds under this new facility will be to fund asset acquisitions. The terms, covenants and restrictions under this facility are substantially the same with our amended secured Revolving Credit Facility. See further discussion in Note 8 to our consolidated financial statements in Item 8.

COVENANTS

The Revolving Credit Facility, Dropdown Credit Facility and senior notes contain covenants that may, among other things, limit or restrict our ability (as well as the ability of our subsidiaries) to:


•	incur additional indebtedness and incur liens on assets to secure certain debt;


•	pay and make certain restricted payments;


•	make distributions from our subsidiaries;


•	dispose of assets in excess of an annual threshold amount;


•	in the case of the Revolving Credit Facility, make certain amendments, modifications or supplements to organization documents and material contracts;


•	in the case of the Revolving Credit Facility, engage in certain business activities;


•	engage in certain mergers or consolidations and transfers of assets; and


•	enter into non-arm’s-length transactions with affiliates.



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MANAGEMENT’S DISCUSSION AND ANALYSIS

We do not believe that these limitations will restrict our ability to pay distributions. Additionally, the Revolving Credit Facility contains covenants that require us to maintain certain interest coverage and leverage ratios. We submit compliance certifications to the bank quarterly, and we were in compliance with our debt covenants as of and for the year ended December 31, 2016.

SENIOR NOTES ISSUANCES

5.250% SENIOR NOTES DUE 2025. On December 2, 2016, we completed a registered offering of $750 million aggregate principal amount of the 5.250% Senior Notes due in 2025. The proceeds from this offering were used to pay amounts outstanding under the Dropdown Credit Facility.

The 2025 Senior Notes have no sinking fund requirements. We may redeem some or all of the 2025 Notes prior to January 15, 2021, at a make-whole price, plus any accrued and unpaid interest. On or after January 15, 2021, the 2025 Notes may be redeemed at premiums equal to 2.625% through January 15, 2022; 1.313% through January 15, 2023; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 105.250% of face value with proceeds from certain equity issuances through January 15, 2020. The 2025 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

6.125% SENIOR NOTES DUE 2021 AND 6.375% SENIOR NOTES DUE 2024. On May 9, 2016, we completed a registered offering of $250 million aggregate principal amount of 6.125% Senior Notes due 2021 (“2021 Notes”) and $450 million aggregate principal amount of 6.375% Senior Notes due 2024 (“2024 Notes”). We used the proceeds of the offering of the 2021 notes to repay amounts outstanding under the Dropdown Credit Facility and the proceeds of the offering of the 2024 Notes to repay amounts outstanding under our Revolving Credit Facility and for general partnership purposes.

The 2021 Notes were issued under the same indenture governing the existing $550 million of the 6.125% Senior Notes due 2021 issued in August 2013 and have the same terms as those senior notes. The 2021 Notes have no sinking fund requirements. The 2021 Notes may be redeemed at premiums equal to 4.594% through October 15, 2017; 3.063% from October 15, 2017 through October 15, 2018; 1.531% from October 15, 2018 through October 15, 2019; and at par thereafter, plus accrued and unpaid interest. The 2021 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

The 2024 Notes have no sinking fund requirements. We may redeem some or all of the 2024 Notes, prior to May 1, 2019, at a make-whole price plus accrued and unpaid interest, if any. On or after May 1, 2019, the 2024 Notes may be redeemed at premiums equal to 4.781% through May 1, 2020; 3.188% from May 1, 2020 through May 1, 2021; 1.594% from May 1, 2021 through May 1, 2022; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 106.375% face value with proceeds from certain equity issuances through May 1, 2019. The 2024 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

SENIOR NOTES EXCHANGE

On February 26, 2016, the Partnership commenced an offer to exchange (the “Exchange”) its existing unregistered 5.50% Senior Notes due 2019 (“2019 Notes”) and 6.25% Senior Notes due 2022 (“2022 Notes”) (together, “Unregistered Notes”) for an equal principal amount of 5.50% Senior Notes due 2019 and 6.25% Senior Notes due 2022 (the “Exchange Notes”), respectively, that were registered under the Securities Act of 1933, as amended. On April 14, 2016, the Exchange was completed for all of the 2019 Notes and substantially all of the 2022 Notes. The terms of the Exchange Notes are identical in all material respects (including principal amount, interest rate, maturity and redemption rights) to the Unregistered Notes for which they were exchanged, except that the Exchange Notes generally are not subject to transfer restrictions. The Exchange fulfills all of the requirements of the registration rights agreements for the Unregistered Notes.

DEBT REPAYMENTS

On February 3, 2016, we paid the full amount of the unsecured term loan facility (the “Unsecured Term Loan Facility”), including accrued interest, with proceeds drawn from the Dropdown Credit Facility. All commitments under the Unsecured Term Loan Facility were terminated effective with the repayment and an immaterial amount of unamortized debt issuance costs were expensed.



		December 31, 2016 \| 35



MANAGEMENT’S DISCUSSION AND ANALYSIS

SOURCES AND USES OF CASH

COMPONENTS OF CASH FLOWS (in millions)



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
Cash Flows From (Used In):
Operating Activities	$	498		$	436		$	165
Investing Activities	(318		)	(389		)	(2,690		)
Financing Activities	492			(50		)	2,521
Increase (Decrease) in Cash and Cash Equivalents	$	672		$	(3	)	$	(4	)


(a)	Includes the historical results related to the Partnership and Predecessors for the years ended December 31, 2016, 2015 and 2014.

2016 COMPARED TO 2015

Net cash from operating activities increased $62 million to $498 million in 2016 from $436 million in 2015. The increase in net cash from operating activities was primarily due to a significant contribution of operating income from the Terminalling and Transportation segment driven by commercial agreements executed in connection with the LA Storage and Handling Assets and Alaska Storage and Terminalling Assets acquisitions.

Net cash used in investing activities decreased $71 million to $318 million in 2016 compared to $389 million in 2015. The decrease was primarily driven by a decline in the amounts spent on capital expenditure projects during 2016. See “Capital Expenditures” below for a discussion of the various maintenance and growth projects in 2016. This decrease was partially offset by cash used for acquisitions related to the Alaska Storage and Terminalling Assets acquisition and deposit for the North Dakota Gathering and Processing Assets.

Net cash from financing activities during 2016 totaled $492 million as compared to net cash used in financing activities of $50 million in 2015. The change of $542 million was primarily due to a $1.2 billion increase in the proceeds from debt offerings partially offset by the $251 million repayment of the term loan facility, which is discussed in the “Debt Overview” above. In addition, proceeds from issuance of common units and general partner units increased $265 million in 2016. Partially offsetting the items contributing to financing activities were an increase to distributions in connection with acquisitions of $510 million with both the Alaska Storage and Terminalling Assets and Northern California Terminalling and Storage Assets acquisitions occurring in 2016 compared to the LA Storage and Handling Assets occurring in 2015. Quarterly distributions to unitholders and the general partner also increased $153 million.

2015 COMPARED TO 2014

Net cash from operating activities increased $271 million to $436 million in 2015 from $165 million in 2014. The increase in net cash from operating activities was primarily due to a significant contribution of operating income from the Rockies Natural Gas Business Acquisition for an entire year as well as incremental cash flow from growth on the High Plains System and commercial agreements executed in connection with the West Coast Logistics Assets Acquisition.

Net cash used in investing activities decreased $2.3 billion to $389 million in 2015 compared to $2.7 billion in 2014. The decrease was primarily driven by the cash paid for the Rockies Natural Gas Business of $2.5 billion in 2014. This decrease was partially offset by higher capital expenditures in 2015 compared to 2014 related to the construction of the Connolly Gathering System, the second phase of the Bakken area storage hub, and various projects on our Southern California distribution system. See “Capital Expenditures” below for a discussion of the various maintenance and growth projects in 2015.

Net cash used in financing activities during 2015 totaled $50 million as compared to net cash from financing activities of $2.5 billion in 2014. The change of $2.6 billion was primarily due to financing activities in 2014, which included the net proceeds of $1.4 billion resulting from the public offering of 2.1 million common units representing limited partner interests and the registered public offering of 23.0 million common units in connection with the Rockies Natural Gas Business Acquisition and $1.3 billion of aggregate principal senior notes, completed in a private offering Senior Notes Offering. We paid higher quarterly cash distributions totaling $308 million during 2015 compared to $183 million paid in 2014. Additionally, we paid $22 million in distributions to the common public unitholders of QEPM and QEPM’s subsidiaries during 2015.



36 \| Tesoro Logistics LP



MANAGEMENT’S DISCUSSION AND ANALYSIS

Historically, the Predecessors’ sources of liquidity included cash generated from operations and funding from Tesoro. Cash receipts were deposited in Tesoro’s bank accounts and all cash disbursements were made from those accounts. The Sponsor contribution of $119 million, $116 million and $53 million included in cash from financing activities in 2016, 2015 and 2014, respectively, funded the cash portion of the net loss for the Predecessors.

CAPITAL EXPENDITURES

The Partnership’s operations are capital intensive, requiring investments to expand, upgrade or enhance existing operations and to maintain assets and ensure regulatory compliance. Growth capital expenditures include expenditures to purchase or construct new assets and to expand existing facilities or services that may increase throughput capacity on our pipelines, in our terminals and at our processing facilities, increase storage capacity, increase well connections and compression as well as other services at our facilities. Maintenance capital expenditures include expenditures required to maintain equipment reliability and integrity and to ensure regulatory compliance. Actual and estimated amounts described below include amounts representing capitalized interest and labor. Our capital expenditures are funded primarily with cash generated from operations, reimbursements for certain growth and maintenance capital expenditures, borrowings under our Revolving Credit Facility and issuances of additional debt and equity securities, as needed.

2016 CAPITAL EXPENDITURES. During 2016, we spent $198 million, net of $11 million in reimbursements from entities including Tesoro, on growth capital projects and $42 million, net of $22 million in reimbursements from entities including Tesoro, on maintenance capital projects.

2017 EXPECTED CAPITAL EXPENDITURES. We estimate that our expected 2017 capital expenditures will be approximately $325 million, or $295 million net of reimbursements from entities including Tesoro, with whom we contract to provide services. We continuously evaluate our capital expenditures in light of conditions in the market environment and business requirements.

Cost estimates for projects currently in process or under development are subject to further review, analysis and permitting requirements, which may result in revisions to our current spend estimates.

MAJOR CAPITAL PROJECTS IN PROCESS OR UNDER DEVELOPMENT (in millions)



Major Projects	Total Project Expected Capital Expenditures		Actual 2016 Capital Expenditures
Gathering and Processing Segment:
Uinta Compression (a)	$	50 - 60	$	36
Bakken Area Storage Hub (b)		25 - 30	5
High Plains Pipeline Expansion (c)		20 - 30	12
Terminalling and Transporting Segment:
Los Angeles Refinery Interconnect Pipeline System (d)		150 - 200	—
Terminal Expansions (e)		30 - 40	14
Avon Wharf Project (f)		185-195	58


(a)	Projects to increase compression for our Uinta natural gas gathering systems and expand our gathering system in the Uinta basin. We expect incremental volumes through our processing system upon the completion of the project.


(b)	The construction of the second phase of the Bakken Area Storage Hub provides storage tanks located in two strategic areas of the basin. With its completion during the first quarter of 2016, storage capacity has grown to over one million barrels. Amounts shown above for capital expenditures represent actual amounts spent on this completed project.


(c)	Projects to expand crude oil gathering throughput capacity on the High Plains Pipeline in McKenzie County, North Dakota. The expansion project’s expected capital expenditures may be reduced as a result of Tesoro’s recent acquisition of Great Northern Midstream and associated BakkenLink pipeline.


(d)	The pipeline interconnect project at the Los Angeles refinery is designed to provide direct connectivity between Tesoro’s refining sites. The proposed project is subject to final Board of Directors approval, project scoping, engineering and regulatory approval.


(e)	Projects to increase the throughput capacity and service capabilities at our crude oil and refined products terminals.

(f)

In connection with the Northern California Terminalling and Storage Assets acquisition, we acquired the Avon Wharf in Martinez, California. Our Predecessor’s regulatory and compliance project for the Avon Wharf was required under the California building code for Marine Oil Terminal Engineering and Maintenance Standards (“MOTEMS”). The project replaces the marine berth with a MOTEMS compliant structure that will improve clean product movements. The project is nearly complete with expected remaining capital expenditures of $8 million, which will be reimbursed by Tesoro.



		December 31, 2016 \| 37



MANAGEMENT’S DISCUSSION AND ANALYSIS

LONG-TERM COMMITMENTS

We have numerous contractual commitments for purchases associated with the operation of our assets, our debt service and our operating and capital leases (see Notes 8 and 10 to our consolidated financial statements in Item 8). We also have minimum contractual spending requirements for certain capital projects.

SUMMARY OF CONTRACTUAL OBLIGATIONS (in millions)



Contractual Obligation	2017		2018		2019		2020		2021		Thereafter		Total
Long-term debt obligations (a)	$	232	$	232	$	726	$	671	$	1,287	$	2,225	$	5,373
Capital lease obligations (b)	1		1		1		1		1		7		12
Operating lease obligations (c)	16		12		11		9		8		70		126
Other purchase obligations (d)	86		86		86		87		49		—		394
Capital expenditure obligations (e)	82		—		—		—		—		—		82
Total Contractual Obligations	$	417	$	331	$	824	$	768	$	1,345	$	2,302	$	5,987


(a)	Includes maturities of principal and interest payments. Amounts and timing may be different from our estimated commitments due to potential voluntary debt prepayments and borrowings.


(b)	Capital lease obligations include amounts classified as interest.


(c)	Minimum operating lease payments for operating leases having initial or remaining non-cancellable lease terms in excess of one year primarily related to our truck vehicle leases and leases for pipelines, terminals, pump stations and property leases.

(d)

Purchase obligations include enforceable and legally binding service agreement commitments that meet any of the following criteria: (1) they are non-cancellable, (2) we would incur a penalty if the agreement was canceled, or (3) we must make specified minimum payments even if we do not take delivery of the contracted products or services. If we can unilaterally terminate the agreement simply by providing a certain number of days’ notice or by paying a termination fee, we have included the termination fee or the amount that would be paid over the notice period. Contracts that can be unilaterally terminated without a penalty are not included. Future purchase obligations primarily include NGLs transportation costs, fractionation fees, and fixed charges under the Third Amended and Restated Omnibus Agreement (“Amended Omnibus Agreement”), and the Secondment and Logistics Services Agreement. Our Amended Omnibus Agreement remains in effect between the applicable parties until a change in control of the Partnership. As we are unable to estimate the termination of the omnibus agreement, we have included the fees for each of the five years following December 31, 2016 for the Amended Omnibus Agreement for disclosure purposes in the table above.


(e)	Minimum contractual spending requirements for certain capital projects.

We also have other noncurrent liabilities pertaining to our environmental liabilities and asset retirement obligations. With the exception of amounts classified as current, there is uncertainty as to the timing of future cash flows related to these obligations. As such, we have excluded these future cash flows from the table above. See additional information on environmental liabilities and asset retirement obligations in Note 10 and Note 1, respectively, to our consolidated financial statements in Item 8.

OFF BALANCE SHEET ARRANGEMENTS

We have not entered into any transactions, agreements or other contractual arrangements, other than our leasing arrangements described in Note 10 to our consolidated financial statements in Item 8 that would result in off-balance sheet liabilities.

ENVIRONMENTAL AND OTHER MATTERS

ENVIRONMENTAL REGULATION. 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 remediate environmental damage from any discharge of petroleum, natural gas or chemical substances from our facilities or require us to 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.

Future expenditures may be required to comply with the federal, state and local environmental requirements for our various sites, including our storage facilities, pipelines, gas processing complexes and refined products terminals. The impact of these legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our liquidity, financial position or results



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MANAGEMENT’S DISCUSSION AND ANALYSIS

of operations. Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and subsequent acquisitions from Tesoro.

ENVIRONMENTAL LIABILITIES AND LEGAL. Contamination resulting from spills of crude oil, natural gas and refined products is not unusual within the terminalling, pipeline, gathering or processing industries. Historic spills at certain of our assets as a result of past operations have resulted in contamination of the environment, including soils and groundwater. Site conditions, including soils and groundwater, are being evaluated at our properties where releases of hydrocarbons and other wastes have occurred. A number of our properties have known hydrocarbon or other hazardous material contamination in the soil and groundwater. See below for our discussion of the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement for more information regarding the indemnification of certain environmental matters provided to us by Tesoro.

The Partnership has been party to various environmental matters arising in the ordinary course of business. The outcome of these matters cannot always be accurately predicted, but the Partnership recognizes liabilities for these matters based on estimates and applicable accounting guidelines and principles. We have accrued liabilities for these expenses and believe these accruals are adequate based on current information and projections that can be reasonably estimated. Our environmental accruals are estimates using internal and third-party assessments and available information to date. It is possible that these estimates will change as more information becomes available. Our accruals for these environmental expenditures totaled $22 million and $33 million at December 31, 2016 and 2015, respectively.

TIOGA, NORTH DAKOTA CRUDE OIL PIPELINE RELEASE. In September 2013, the Partnership responded to the Crude Oil Pipeline Release. The environmental liabilities related to the Crude Oil Pipeline Release include amounts estimated for remediation activities that will be conducted during the next few years to restore the site for agricultural use. We accrued an additional $7 million during the year ended December 31, 2016, to reflect improved scope definition and estimates, which resulted in an increase in the total estimated cost associated with the project. This incident was covered by our pollution liability insurance policy, subject to a $1 million deductible and a $25 million loss limit in place at that time. Pursuant to this policy, there were no insurance recovery receivables related to the Crude Oil Pipeline Release at both December 31, 2016 and 2015, and $18 million at December 31, 2014. The estimated remediation costs of $73 million exceeded our policy loss limit by $48 million as of December 31, 2015. We received no insurance proceeds for the year ended December 31, 2016, and $18 million and $7 million in reimbursement of costs incurred during the years ended December 31, 2015 and 2014, respectively.

See Note 10 to our consolidated financial statements in Item 8 for additional information regarding our environmental liabilities and legal proceedings.

TESORO INDEMNIFICATION. Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and the subsequent Acquisitions from Tesoro. See Note 3 to our consolidated financial statements in Item 8 for additional information regarding our Amended Omnibus Agreement and the Carson Assets Indemnity Agreement.

ACCOUNTING STANDARDS

CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our significant accounting policies and recent accounting developments are described in Note 1 to our consolidated financial statements in Item 8. We prepare our financial statements in conformity with U.S. GAAP, which requires us to make estimates and assumptions about future events that affect the amounts reported in the financial statements and accompanying footnotes. Actual results could differ from those estimates. We believe that the following discussion of policies to be the most important to the portrayal of our financial condition and results of operations and require management’s most difficult, subjective and complex judgments.

IMPAIRMENT OF LONG-LIVED ASSETS. Long-lived assets (which include property, plant, and equipment and intangible assets) are evaluated for potential impairment when an asset disposition is probable or when there are indicators of impairment (for example, current period operating losses combined with a history of operating losses) and, if so, assessing whether the asset net book values are recoverable from estimated future undiscounted cash flows. The actual amount of an impairment loss to be recorded, if any, is equal to the amount by which the asset’s net book value exceeds its fair market value. Fair market value is based on the present values of estimated future cash flows in the absence of quoted market prices. Estimates of future cash flows and fair market values of assets require subjective assumptions with regard to several factors, including an assessment of global market conditions, future operating results and forecasts of the remaining useful lives of the assets. Actual results could



		December 31, 2016 \| 39



MANAGEMENT’S DISCUSSION AND ANALYSIS

differ from those estimates. Providing sensitivity analysis if other assumptions were used in performing the impairment evaluations is not practicable due to the significant number of assumptions involved in the estimates.

GOODWILL. Goodwill represents the excess of the consideration paid over the fair value of the net assets acquired in a business combination. Goodwill acquired in a business combination is not amortized, but instead tested for impairment at least annually or more frequently should an event occur or circumstances indicate that the carrying amount may be impaired. Such events or circumstances may be a significant change in business climate, economic and industry trends, legal factors, negative operating performance indicators, significant competition, changes in strategy, or disposition of a reporting unit or a portion thereof. Goodwill impairment testing is performed at the reporting unit level on November 1 of each year and when circumstances change that might indicate impairment.

We test goodwill for impairment by performing an optional qualitative assessment process and/or using a two-step quantitative assessment process. If we choose to perform a qualitative assessment process and determine it is more likely than not (that is, a likelihood of more than 50 percent) that the carrying value of the net assets is more than the fair value of the reporting unit, the two-step quantitative assessment process is then performed; otherwise, no further testing is required. We may elect not to perform the qualitative assessment process and, instead, proceed directly to the two step quantitative assessment process. For reporting units where the two-step quantitative assessment process is performed, the first step involves comparing the carrying value of net assets, including goodwill, to the fair value of the reporting unit. If the fair value exceeds its carrying amount, goodwill is not considered impaired and the second step of the process is unnecessary. If the carrying amount of a reporting unit’s goodwill exceeds its fair value, the second step measures the impairment loss, if any.

We elected to perform our annual goodwill impairment analysis using a two-step quantitative assessments process on $117 million of goodwill recorded in five reporting units. As part of our two-step quantitative goodwill impairment process for the five reporting units, we engaged a third-party appraisal firm to assist in the determination of estimated fair value for each reporting unit. This determination includes estimating the fair value of each reporting unit using both the income and market approaches. The income approach requires management to estimate a number of factors for each reporting unit, including projected future operating results, economic projections, anticipated future cash flows and discount rates. The market approach estimates fair value using comparable marketplace fair value data from within a comparable industry grouping. The determination of the fair value of the reporting units requires us to make significant estimates and assumptions. These estimates and assumptions primarily include, but are not limited to, the selection of appropriate peer group companies, control premiums appropriate for acquisitions in the industries in which we compete, the discount rates, terminal growth rates, and forecasts of revenue, operating income, depreciation and amortization and capital expenditures.

We determined that no impairment charges resulted from our November 1, 2016 goodwill impairment assessment. Furthermore, the fair value of each of the five reporting units tested in step one of the goodwill impairment test were materially in excess of the carrying value, and as such, we were not required to perform step two.

ENVIRONMENTAL LIABILITIES. At December 31, 2016, our total environmental liabilities included in other current liabilities and other noncurrent liabilities were $22 million. We record environmental liabilities when environmental assessments and/or proposed environmental remedies are probable and can be reasonably estimated. Usually, the timing of our accruals coincides with assessing the liability and then completing a feasibility study or committing to a formal plan of action. When we complete our analysis or when we commit to a plan of action, we accrue a liability based on the minimum range of the expected costs, unless we consider another amount more likely. We base our cost estimates on the extent of remedial actions required by applicable governing agencies, experience gained from similar environmental projects and the amounts to be paid by other responsible parties.

Accruals for our environmental liabilities require judgment due to the uncertainties related to the magnitude of the liability and timing of the remediation effort. Our environmental liability estimates are subject to change due to potential changes in environmental laws, regulations or interpretations, additional information related to the extent and nature of the liability, and potential improvements in remediation technologies. We do not discount our estimated liabilities to present value.

As of December 31, 2016, we carry a pollution liability insurance policy, which is subject to a $1 million deductible ($5 million pipeline deductible) and a $150 million loss limit. We record insurance recoveries during the year when recovery is probable and can be reasonably estimated.

ACQUISITIONS. We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed with acquisitions, other than a combination under common control, at their estimated fair values as of the date of acquisition. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired is recorded as goodwill. Significant judgment is required in estimating the fair value of assets acquired. As a result, in the case of significant acquisitions, we obtain the assistance of third-party valuation specialists in estimating fair values of tangible and intangible assets based on available historical information and on expectations and assumptions about the future, considering the perspective of marketplace participants. While management believes those expectations and assumptions are reasonable, they are inherently



40 \| Tesoro Logistics LP



MANAGEMENT’S DISCUSSION AND ANALYSIS

uncertain. Unanticipated market or macroeconomic events and circumstances may occur, which could affect the accuracy or validity of the estimates and assumptions.

NEW ACCOUNTING STANDARDS AND DISCLOSURES

New accounting standards and disclosures are discussed in Note 1 to our consolidated financial statements in Item 8.



		December 31, 2016 \| 41



QUANTITATIVE AND QUALITATIVE DISCLOSURE

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISK

Market risk is the risk of loss arising from adverse changes in market rates and prices. As we do not own the refined products, natural gas or crude oil that are shipped through our pipelines, distributed through our terminals or held in our storage facilities, we have minimal direct exposure to risks associated with fluctuating commodity prices. In addition, our commercial agreements with Tesoro are indexed for inflation and contain fuel surcharge provisions designed to substantially mitigate our exposure to increases in diesel fuel prices and the cost of other supplies used in our business. As part of our acquisition of the North Dakota Gathering and Processing Assets, we acquired certain natural gas gathering and processing contracts structured as Percent of Proceeds (“POP”) arrangements. Under these POP arrangements, we gather and process the producers’ natural gas and retain and market a portion of the natural gas and NGLs and remit a percentage of the proceeds to the producer. Under these arrangements, we will have exposure to fluctuations in commodity prices; however, this exposure is not expected to be material to our results of operations. Also, our exposure to commodity price risk related to imbalance gains and losses or to diesel fuel or other supply costs is not expected to be material to our results of our operations, financial position, and cash flows and we do not intend to hedge our exposure.

We are exposed to a limited degree of commodity price risk with respect to our gathering contracts. Specifically, pursuant to our contracts, we retain and sell condensate that is recovered during the gathering of natural gas. Thus, a portion of our revenue is dependent on the price received for the condensate. Condensate historically sells at a price representing a slight discount to the price of crude oil. We consider our exposure to commodity price risk associated with these arrangements to be minimal based on the amount of revenues generated under these arrangements compared to our overall revenues. We do not hedge our exposure using commodity derivative instruments because of the minimal impact of commodity price risk on our liquidity, financial position and results of operations. Assuming all other factors remained constant, a $1 change in condensate pricing, based on our quarter-to-date average throughput, would be immaterial to our consolidated operating income. Actual results may differ from our expectation above.

Under a keep-whole agreement, normally a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a British Thermal Unit content equivalent to the NGLs removed. We have entered into an agreement with Tesoro to transfer the market risk associated with the purchase of natural gas. See Note 3 to our consolidated financial statements in Item 8 for additional information on our keep-whole agreement.

INTEREST RATE RISK

Our use of fixed or variable rate debt directly exposes us to interest rate risk. Fixed rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates or that our current fixed rate debt may be higher than the current market. Variable-rate debt, such as borrowings under our Revolving Credit Facility, exposes us to short-term changes in market rates that impact our interest expense. The fair value of our debt was estimated primarily using quoted market prices. The carrying and fair values of our debt were approximately $4.1 billion and $4.3 billion at December 31, 2016, respectively, and approximately $2.9 billion and $2.8 billion for both the carrying and fair values at December 31, 2015. These carrying and fair values of our debt do not consider the unamortized issuance costs, which are netted against our total debt. Unless interest rates increase significantly in the future, our exposure to interest rate risk should be minimal. With all other variables constant, a 0.25% change in the interest rate associated with the borrowings outstanding would change annual interest expense by less than $1 million under our Revolving Credit Facility and would have no impact under the Dropdown Credit Facility at December 31, 2016. Any change in interest rates would affect cash flows, but not the fair value of the debt we incur under our Revolving Credit Facility. We currently do not use interest rate swaps to manage our exposure to interest rate risk; however, we continue to monitor the market and our exposure, and may in the future enter into these transactions to mitigate risk. We believe in the short-term we have acceptable interest rate risk and continue to monitor the risk on our long-term obligations. There were no borrowings outstanding under the Dropdown Credit Facility and $330 million borrowings outstanding under the Revolving Credit Facility as of December 31, 2016.



42 \| Tesoro Logistics LP



FINANCIAL STATEMENTS

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Tesoro Logistics GP, LLC and

Unitholders of Tesoro Logistics LP

We have audited the accompanying consolidated balance sheets of Tesoro Logistics LP as of December 31, 2016 and 2015, and the related consolidated statements of operations, partners’ equity and cash flows for each of the three years in the period ended December 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the 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. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tesoro Logistics LP at December 31, 2016 and 2015, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Tesoro Logistics LP’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 Framework), and our report dated February 21, 2017 expressed an unqualified opinion thereon.

San Antonio, Texas

February 21, 2017,

except for Note 13, as to which the date is August 21, 2017



		December 31, 2016 \| 43



FINANCIAL STATEMENTS

TESORO LOGISTICS LP

CONSOLIDATED STATEMENTS OF OPERATIONS



		Years Ended December 31,
	Note	2016 (a)			2015 (a)				2014 (a)
		(In millions, except per unit amounts)
Revenues
Affiliate	3	$	715		$	615			$	497
Third-party		505			497				103
Total Revenues		1,220			1,112				600
Costs and Expenses:
Cost of Sales		2			—			—	—
Operating expenses		469			468				324
Imbalance settlement gains, net and reimbursements		(27		)	(40		)		(43		)
General and administrative expenses		95			103				74
Depreciation and amortization expenses		190			187				85
Loss (gain) on asset disposals and impairments		4			1				(4		)
Operating Income		487			393				164
Interest and financing costs, net		(191		)	(150		)		(109		)
Equity in earnings of equity method investments	6	13			7				1
Other Income, net		6			—				—
Earnings Before Income Taxes		315			250				56
Income tax expense		—			1				—
Net Earnings		$	315		$	249			$	56

Loss attributable to Predecessors		$	24		$	43			$	46
Net earnings attributable to noncontrolling interest		—			(20		)		(3		)
Net earnings attributable to partners		339			272				99
General partner’s interest in net earnings, including incentive distribution rights		(152		)	(73		)		(43		)
Limited partners’ interest in net earnings		$	187		$	199			$	56

Net earnings per limited partner unit:
Common - basic		$	1.87		$	2.33			$	0.96
Common - diluted		$	1.87		$	2.33			$	0.96
Subordinated - basic and diluted		$	—		$	—			$	0.62

Weighted average limited partner units outstanding:
Common units - basic		98.2			84.7				54.2
Common units - diluted		98.2			84.8				54.2
Subordinated units - basic and diluted		—			—				5.6

Cash distributions paid per unit		$	3.3070		$	2.8350			$	2.4125


(a)	All periods include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

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



44 \| Tesoro Logistics LP



FINANCIAL STATEMENTS

TESORO LOGISTICS LP

CONSOLIDATED BALANCE SHEETS



		December 31,
	Note	2016			2015 (a)
		(In millions, except unit amounts)
ASSETS
Current Assets
Cash and cash equivalents		$	688		$	16
Receivables, net of allowance for doubtful accounts
Trade		129			139
Affiliate		101			85
Prepayments and other current assets		20			12
Total Current Assets		938			252
Property, Plant, and Equipment, Net	4	3,444			3,681
Acquired Intangibles, Net	5	947			976
Goodwill	5	117			130
Equity Method Investments	6	337			58
Other Noncurrent Assets, Net		77			34
Total Assets		$	5,860		$	5,131

LIABILITIES AND EQUITY
Current Liabilities
Accounts payable
Trade		$	69		$	106
Affiliate		56			48
Accrued interest and financing costs		42			31
Other current liabilities	7	45			61
Total Current Liabilities		212			246
Debt, Net of Unamortized Issuance Costs	8	4,053			2,844
Other Noncurrent Liabilities		53			58
Total Liabilities		4,318			3,148
Commitments and Contingencies	10
Equity
Equity of Predecessors		—			205
Common unitholders: 102,981,495 units issued and outstanding (93,478,326 in 2015)		1,608			1,707
General partner: 2,100,900 units issued and outstanding (1,900,515 in 2015)		(66		)	(13		)
Noncontrolling interest		—			84
Total Equity	11	1,542			1,983
Total Liabilities and Equity		$	5,860		$	5,131


(a)	Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

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



		December 31, 2016 \| 45



FINANCIAL STATEMENTS

TESORO LOGISTICS LP

CONSOLIDATED STATEMENTS OF PARTNERS’ EQUITY



	Equity of Predecessors (a)			Partnership									Non-controlling Interest			Total
	Equity of Predecessors (a)			Common			Subordinated			General Partner			Non-controlling Interest			Total
	(In millions)
Balance at December 31, 2013	$	189		$	459		$	(161	)	$	(53	)	$	—		$	434
Sponsor contributions of equity to the Predecessors	53			—			—			—			—			53
Loss attributable to Predecessors	(46		)	—			—			—			—			(46		)
Net liabilities not assumed by Tesoro Logistics LP	1			—			—			—			—			1
Allocation of net assets acquired by the unitholders	(29		)	28			—			1			—			—
Equity offering, net of issuance costs	—			1,449			—			29			—			1,478
Quarterly distributions to unitholders and general partner	—			(131		)	(17		)	(35		)	—			(183		)
Subordinated unit conversion	—			(165		)	165			—			—			—
Distributions to unitholders and general partner related to acquisitions	—			(237		)	—			(6		)	—			(243		)
Contributions	—			27			—			2			—			29
Net earnings excluding loss attributable to Predecessors	—			43			13			43			3			102
Noncontrolling interest acquired	—			—			—			—			432			432
Other	—			1			—			—			—			1
Balance at December 31, 2014	$	168		$	1,474		$	—		$	(19	)	$	435		$	2,058
Sponsor contributions of equity to the Predecessors	116			—			—			—			—			116
Loss attributable to Predecessors	(43		)	—			—			—			—			(43		)
Net liabilities not assumed by Tesoro Logistics LP	3			—			—			—			—			3
Allocation of net assets acquired by the unitholders	(39		)	37			—			2			—			—
Equity offering, net of issuance costs	—			95			—			4			—			99
Quarterly distributions to unitholders and general partner	—			(240		)	—			(68		)	(22		)	(330		)
Distributions to unitholders and general partner related to acquisitions	—			(235		)	—			(15		)	—			(250		)
Contributions	—			22			—			10			—			32
Net earnings excluding loss attributable to Predecessors	—			199			—			73			20			292
QEPM Merger	—			351			—			—			(351		)	—
Other	—			4			—			—			2			6
Balance at December 31, 2015	$	205		$	1,707		$	—		$	(13	)	$	84		$	1,983
Sponsor contributions of equity to the Predecessors	119			—			—			—			—			119
Loss attributable to Predecessors	(24		)	—			—			—			—			(24		)
Net liabilities not assumed by Tesoro Logistics LP	22			—			—			—			—			22
Allocation of net assets acquired by the unitholders	(322		)	310			—			12			—			—
Equity offering under ATM Program, net of issuance costs	—			71			—			—			—			71
Proceeds from issuance of units, net of issuance costs	—			293			—			—			—			293
Effect of deconsolidation of RGS	—			—			—			—			(84		)	(84		)
Quarterly distributions to unitholders and general partner	—			(324		)	—			(137		)	—			(461		)
Distributions to unitholders and general partner related to acquisitions	—			(679		)	—			(86		)	—			(765		)
Contributions	—			39			—			3			—			42
Net earnings excluding loss attributable to Predecessors	—			187			—			152			—			339
Other	—			4			—			3			—			7
Balance at December 31, 2016	$	—		$	1,608		$	—		$	(66	)	$	—		$	1,542


(a)	Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

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



46 \| Tesoro Logistics LP



FINANCIAL STATEMENTS

TESORO LOGISTICS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
	(In millions)
Cash Flows From (Used In) Operating Activities:
Net earnings	$	315		$	249		$	56
Adjustments to reconcile net earnings to net cash from operating activities:
Depreciation and amortization expenses	190			187			85
Amortization of debt issuance costs	9			8			6
Unit-based compensation expense	6			6			2
Equity in earnings of equity method investments, net of distributions	16			3			(1		)
Other non-cash operating activities	6			2			4
Changes in receivables	(9		)	(21		)	(8		)
Changes in other current assets	(5		)	(9		)	10
Changes in current liabilities	(22		)	(6		)	9
Changes in other noncurrent assets and liabilities	(8		)	17			2
Net cash from operating activities	498			436			165
Cash Flows From (Used In) Investing Activities:
Capital expenditures	(260		)	(383		)	(221		)
Acquisitions, net of cash acquired	(30		)	(6		)	(2,479		)
Deposits for acquisitions	(33		)	—			—
Other investing activities	5			—			10
Net cash used in investing activities	(318		)	(389		)	(2,690		)
Cash Flows From (Used In) Financing Activities:
Proceeds from debt offering	1,451			250			1,300
Proceeds from issuance of common units, net of issuance costs	364			95			1,449
Proceeds from issuance of general partner units, net of issuance costs	—			4			29
Quarterly distributions to common and subordinated unitholders	(324		)	(240		)	(148		)
Quarterly distributions to general partner	(137		)	(68		)	(35		)
Distributions to noncontrolling interest	—			(22		)	—
Distributions in connection with acquisitions from Tesoro	(760		)	(250		)	(243		)
Borrowings under revolving credit agreements	1,451			476			646
Repayments under revolving credit agreements	(1,426		)	(431		)	(386		)
Repayments of long-term debt including capital leases	(251		)	—			(130		)
Sponsor contributions of equity to the Predecessors	119			116			53
Financing costs	(7		)	—			(21		)
Payments of debt issuance costs	(21		)	(2		)	(19		)
Contribution from general partner	4			—			8
Capital contributions by affiliate	29			22			18
Net cash from (used in) financing activities	492			(50		)	2,521
Increase (Decrease) in Cash and Cash Equivalents	672			(3		)	(4		)
Cash and Cash Equivalents, Beginning of Year	16			19			23
Cash and Cash Equivalents, End of Year	$	688		$	16		$	19


(a)	Adjusted to include the historical results of the Predecessors. See Notes 1 and 2 for further discussion.

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



		December 31, 2016 \| 47



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1 – DESCRIPTION OF BUSINESS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

DESCRIPTION AND NATURE OF BUSINESS

Tesoro Logistics LP (“TLLP” or the “Partnership”) is a fee-based, growth-oriented Delaware limited partnership formed in December 2010 by Tesoro Corporation and its wholly owned subsidiary, Tesoro Logistics GP, LLC (“TLGP”), our general partner in December 2010 to own, operate, develop and acquire logistics assets. Unless the context otherwise requires, references in this report to “we,” “us,” “our,” or “ours” refer to Tesoro Logistics LP, one or more of its consolidated subsidiaries or all of them taken as a whole. Effective August 1, 2017, Tesoro Logistics LP changed its name to Andeavor Logistics LP. Unless the context otherwise requires, references in this report to “Tesoro” or our “Sponsor” refer collectively to Tesoro Corporation and any of its subsidiaries, other than TLLP, its subsidiaries and its general partner.

Our logistics assets are integral to the success of Tesoro’s refining and marketing operations and are used to gather crude oil and to distribute, transport and store crude oil and refined products. We are a full-service logistics company operating primarily in the western and mid-continent regions of the United States. We own and operate a network of crude oil, refined products and natural gas pipelines as well as operate crude oil and refined products truck and marine terminals and provide crude oil and refined product storage capacity. In addition, we own and operate natural gas processing and fractionation complexes.

Effective January 1, 2017, we changed our operating segments to reflect our expanded gathering and processing assets and operations and how our chief operating decision maker (“CODM”) manages our business. Our assets are categorized into a Gathering and Processing segment and a Terminalling and Transportation segment. The consolidated financial statements and accompanying notes included in the Form 10-K for the three years ended December 31, 2016 have been recast for the segment changes described above. See Note 13 for additional information regarding our operating segments.

We generate revenue by charging fees for gathering crude oil and natural gas, for processing natural gas, for terminalling, transporting and storing crude oil, and refined products. We are generally not directly exposed to commodity price risk with respect to any of the crude oil, natural gas, Natural Gas Liquids (“NGLs”) or refined products that we handle, as part of our normal operations. However, we may be subject to nominal commodity risk exposure due to pipeline loss allowance provisions in many of our pipeline gathering and transportation contracts and a nominal amount of condensate retained as part of our natural gas gathering services. For the NGLs that we handle under keep-whole agreements, the Partnership has a fee-based processing agreement with Tesoro which minimizes the impact of commodity price movement during the annual period subsequent to renegotiation of terms and pricing each year. We do not engage in the trading of crude oil, natural gas, NGLs or refined products; therefore we have minimal direct exposure to risks associated with commodity price fluctuations. However, these risks indirectly influence our activities and results of operations over the long term through their effects on our customers’ operations. In the years ended December 31, 2016, 2015 and 2014, 59%, 55% and 83% of our revenue was derived from Tesoro primarily under various long-term, fee-based commercial agreements that generally include minimum volume commitments. QEP Resources accounted for 13% and 16% of our total revenues in the years ended December 31, 2016 and 2015, respectively.

Our Gathering and Processing segment includes crude oil and natural gas pipeline gathering systems and gas processing and fractionation complexes in the Bakken Shale/Williston Basin area of North Dakota and Montana (the “Bakken Region”) and the Green River Basin, Uinta Basin and Vermillion Basin in the states of Utah, Colorado and Wyoming (the “Rockies Region”). Our Terminalling and Transportation segment consists of the Northwest Products Pipeline, which includes a regulated common carrier products pipeline running from Salt Lake City, Utah to Spokane, Washington and a jet fuel pipeline to the Salt Lake City International Airport; a regulated common carrier refined products pipeline system connecting Tesoro’s Kenai refinery to our terminals in Anchorage, Alaska; tankage and related equipment at Tesoro’s Kenai refinery; and crude oil and refined products terminals and storage facilities in the western and midwestern U.S.; marine terminals in California; a rail-car unloading facility in Washington; a petroleum coke handling and storage facility in Los Angeles; and other pipelines, which transport products and crude oil from Tesoro’s refineries to nearby facilities in Salt Lake City and Los Angeles.

PRINCIPLES OF CONSOLIDATED AND BASIS OF PRESENTATION

The accompanying consolidated financial statements include the accounts of TLLP and its subsidiaries. All intercompany accounts and transactions have been eliminated. We have evaluated subsequent events through the filing of this Form 10-K. Any material subsequent events that occurred during this time have been properly recognized or disclosed in our financial statements.



48 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

In 2016, 2015 and 2014, we entered into various transactions with Tesoro and our general partner, TLGP, pursuant to which TLLP acquired from Tesoro the following:


•	tankage, refined product storage, marine terminal terminalling and storage assets, pipelines, causeway and ancillary equipment located in Martinez, California (the “Northern California Terminalling and Storage Assets”) effective November 21, 2016;


•	all of the limited liability company interests in Tesoro Alaska Terminals, LLC, tankage, bulk tank farm, a truck rack and rail-loading facility, terminalling and other storage assets located in Kenai, Anchorage and Fairbanks, Alaska (the “Alaska Storage and Terminalling Assets”) completed in two stages on July 1, 2016 and September 16, 2016;


•	a crude oil and refined products storage tank facility located at Tesoro’s Los Angeles refinery and a 50% fee interest in a pipeline that transports jet fuel from Tesoro’s Los Angeles refinery to the Los Angeles International Airport (the “Los Angeles Storage and Handling Assets”) effective November 12, 2015; and


•	truck terminals, storage tanks, rail loading and unloading facilities and a refined products pipeline (the “West Coast Logistics Assets”) effective July 1, 2014, for the terminals, storage tanks and rail facilities and effective September 30, 2014, for the refined products pipeline (the “West Coast Logistics Assets Acquisition”).

These transactions are collectively referred to as “Acquisitions from Tesoro” and the related assets, liabilities and results of the operations are collectively referred to as the “Predecessors.”

The Acquisitions from Tesoro were transfers between entities under common control. As an entity under common control with Tesoro, we record the assets that we acquire from Tesoro on our consolidated balance sheet at Tesoro’s historical basis instead of fair value. Transfers of businesses between entities under common control are accounted for as if the transfer occurred at the beginning of the period, and prior periods are retrospectively adjusted to furnish comparative information. Accordingly, the accompanying financial statements and related notes of TLLP have been retrospectively adjusted to include the historical results of the assets acquired in the Acquisitions from Tesoro prior to the effective date of each acquisition. See Note 2 for additional information regarding the 2016 and 2015 acquisitions.

The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of our Predecessors at historical cost. The financial statements of our Predecessors have been prepared from the separate records maintained by Tesoro and may not necessarily be indicative of the conditions that would have existed or the results of operations if our Predecessors had been operated as an unaffiliated entity. Our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment, except for the Regulatory Commission of Alaska (“RCA”) tariffs charged to Tesoro on the refined products pipeline included in the acquisition of the West Coast Logistics Assets. Accordingly, the revenues in our Predecessors’ historical combined financial statements relate only to amounts received from third parties for these services and amounts received from affiliates with respect to transportation regulated by the RCA for the refined products pipeline included in the West Coast Logistics Assets Acquisition.

USE OF ESTIMATES

We prepare our consolidated financial statements in conformity with accounting principles generally accepted in the United States of America, which requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and revenues and expenses reported and presented as of and for the periods ended. We review our estimates on an ongoing basis using currently available information. Changes in facts and circumstances may result in revised estimates and actual results could differ from those estimates.

CASH AND CASH EQUIVALENTS

Cash and cash equivalents include bank deposits and low-risk short-term investments with original maturities of three months or less at the time of purchase. Cash equivalents are stated at cost, which approximates market value. We place our cash deposits and temporary cash investments with high credit quality financial institutions. At times, our cash and cash equivalents may be uninsured or in deposit accounts that exceed the Federal Deposit Insurance Corporation insurance limit.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

RECEIVABLES

A portion of the Partnership’s accounts receivable is due from Tesoro. Credit for non-affiliated customers is extended based on an evaluation of each customer’s financial condition and in certain circumstances, collateral, such as letters of credit or guarantees, is required. Our allowance for doubtful accounts is based on various factors including current sales amounts, historical charge-offs and specific accounts identified as high risk. After reasonable efforts to collect the amounts have been exhausted, balances are deemed uncollectible and are charged against the allowance for doubtful accounts. Write-offs were immaterial in 2016, 2015 and 2014. The Company does not have any off-balance-sheet credit exposure related to its customers.

PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment are stated at the lower of historical cost less accumulated depreciation or fair value, if impaired. We capitalize all construction-related direct labor and material costs, as well as indirect construction costs. Indirect construction costs include general engineering and other allocated employee costs. Costs, including complete asset replacements and enhancements or upgrades that increase the original efficiency, productivity or capacity of property, plant and equipment, are also capitalized. The costs of repairs, minor replacements and maintenance projects that do not increase the original efficiency, productivity or capacity of property, plant and equipment are expensed as incurred. We capitalize interest as part of the cost of major projects during the construction period. Capitalized interest totaled $5 million, $9 million and $6 million during 2016, 2015 and 2014, respectively, and is recorded as a reduction to net interest and financing costs in our consolidated statements of operations.

We compute depreciation of property, plant and equipment using the straight-line method, based on the estimated useful life of three to 28 years and salvage value of each asset. When assets are placed into service, we make estimates with respect to their useful lives that we believe are reasonable. However, factors such as maintenance levels, economic conditions impacting the demand for these assets and regulatory or environmental requirements could cause us to change our estimates, thus impacting the future calculation of depreciation. We depreciate leasehold improvements and property acquired under capital leases over the lesser of the lease term or the economic life of the asset.

ASSET RETIREMENT OBLIGATIONS. We record asset retirement obligations (“AROs”) at fair value in the period in which we have a legal obligation to incur costs, whether by government action or contractual arrangement, to retire a tangible asset and can make a reasonable estimate of the fair value of the liability. AROs are calculated based on the present value of the estimated removal and other closure costs using our credit-adjusted risk-free rate given an estimated settlement date for the obligation. We estimate settlement dates by considering our past practice, industry practice, management’s intent and estimated economic lives. AROs included in our consolidated balance sheets were $9 million and $12 million at December 31, 2016 and 2015, respectively.

ACQUIRED INTANGIBLES AND GOODWILL

Acquired intangibles are recorded at fair value as of the date acquired and consist of customer relationships obtained in connection with the acquisition all of the limited liability company interests of QEP Field Services, LLC, (the “Rockies Natural Gas Business Acquisition”). The value for the identified customer relationships consists of cash flow expected from existing contracts and future arrangements from the existing customer base. We amortize acquired intangibles with finite lives on a straight-line basis over an estimated weighted average useful life of 35 years and we include the amortization in depreciation and amortization expenses on our consolidated statements of operations.

Goodwill represents the amount the purchase price exceeds the fair value of net assets acquired in a business combination. We do not amortize goodwill or indefinite-lived intangible assets. The goodwill recorded for the Rockies Natural Gas Business represents future organic growth opportunities, anticipated synergies and intangible assets that did not qualify for separate recognition. We are required, however, to review goodwill and indefinite-lived intangible assets for impairment annually, or more frequently if events or changes in business circumstances indicate the book value of the assets may not be recoverable. In such circumstances, we record the impairment in loss on asset disposals and impairments in our consolidated statements of operations. We review the recorded value of goodwill for impairment on November 1^st of each year, or sooner if events or changes in circumstances indicate the carrying amount may exceed fair value using qualitative and/or quantitative assessments at the reporting level. There were no impairments of goodwill during the years ended December 31, 2016, 2015 and 2014.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

IMPAIRMENT OF LONG-LIVED ASSETS

We review property, plant and equipment and other long-lived assets, including acquired intangibles with finite lives, for impairment whenever events or changes in business circumstances indicate the net book values of the assets may not be recoverable. Impairment is indicated when the undiscounted cash flows estimated to be generated by those assets are less than the assets’ net book value. If this occurs, an impairment loss is recognized for the difference between the asset fair value and net book value. Factors that indicate potential impairment include: a significant decrease in the market value of the asset, operating or cash flow losses associated with the use of the asset and a significant change in the asset’s physical condition or use.

INVESTMENTS IN EQUITY METHOD INVESTMENTS

For equity investments that are not required to be consolidated under the variable or voting interest model, we evaluate the level of influence we are able to exercise over an entity’s operations to determine whether to use the equity method of accounting. Our judgment regarding the level of control over an equity method investment includes considering key factors such as our ownership interest, participation in policy-making and other significant decisions and material intercompany transactions. Amounts recognized for equity method investments are included in equity method investments in our consolidated balance sheet and adjusted for our shares of the net earnings and losses of the investee and cash distributions, which are included in our consolidated statements of operations and our consolidated statements of cash flows. Amounts recognized for earnings in excess of distributions of our equity method investments are included in the operating section of our consolidated statements of cash flows. We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate that the carrying amounts of such investments may be impaired. A loss is recorded in earnings in the current period to write down the carrying value of the investment to fair value if a decline in the value of an equity method investment is determined to be other than temporary.

The principal equity method investments and TLLP’s ownership percentage as of December 31, 2016 were Rendezvous Gas Services, L.L.C. (“RGS”), in which we own a 78% ownership interest, Three Rivers Gathering, L.L.C. (“TRG”), in which we own a 50% ownership interest, and Uintah Basin Field Services, L.L.C. (“UBFS”), in which we own a 38% ownership interest. All entities are limited liability companies engaged in gathering and compressing natural gas.

FINANCIAL INSTRUMENTS

Financial instruments including cash and cash equivalents, receivables, accounts payable and accrued liabilities are recorded at their carrying value. We believe the carrying value of these financial instruments approximates fair value. Our fair value assessment incorporates a variety of considerations, including:


•	the short term duration of the instruments (less than two percent for both our trade payables and third-party receivables have been outstanding for greater than 90 days); and


•	the expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The evaluation of our third-party receivables with a short-term duration excludes amounts that are greater than 90 days related to XTO Energy Inc.’s (“XTO”) legal dispute with QEP Field Services, LLC (“QEPFS”). See further discussion regarding the XTO litigation in Note 10.

The fair value of our senior notes is based on prices from recent trade activity and is categorized in level 2 of the fair value hierarchy. The carrying value and fair value of our debt were approximately $4.1 billion and $4.3 billion at December 31, 2016, respectively, and were approximately $2.9 billion and $2.8 billion at December 31, 2015, respectively. These carrying and fair values of our debt do not consider the unamortized issuance costs, which are netted against our total debt.

INCOME TAXES

We are a limited partnership, with the exception of one of our subsidiaries, and are not subject to federal or state income taxes. Our taxable income or loss is included in the federal and state income tax returns of our partners. Taxable income may vary substantially from income or loss reported for financial reporting purposes due to differences in the tax bases and financial reporting bases of assets and liabilities, and due to certain taxable income allocation requirements of the partnership agreement. We are unable to readily determine the net difference in the bases of our assets and liabilities for financial and tax reporting purposes because individual unitholders have different investment bases depending upon the timing and price of acquisition of their partnership units.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Upon the closing of the merger of QEP Midstream Partners, LP (“QEPM”), as discussed further in Note 2, QEP Midstream GP, LLC, the general partner of QEPM and wholly-owned subsidiary of TLLP, made an election to be treated as a corporation for income tax purposes. As a result, we have recognized $1 million of deferred tax expense related to the difference in QEP Midstream GP, LLC’s book and tax basis in its investment in QEPM.

Management is required to evaluate uncertain tax positions taken by the Partnership. The financial statement effects of a tax position are recognized when the position is more likely than not, based on the technical merits, to be sustained upon examination by the Internal Revenue Service. Management has analyzed the tax positions taken by the Partnership and has concluded that there are no uncertain positions taken or expected to be taken.

CONTINGENCIES

ENVIRONMENTAL MATTERS. We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. Our environmental liabilities are estimates using internal and third-party assessments and available information to date. It is possible these estimates will change as additional information becomes available.

We capitalize environmental expenditures that extend the life or increase the capacity of facilities as well as expenditures that prevent environmental contamination. We expense costs that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation. We record liabilities when environmental assessments and/or remedial efforts are probable and can be reasonably estimated. Cost estimates are based on the expected timing and the extent of remedial actions required by governing agencies, experience gained from similar sites for which environmental assessments or remediation have been completed, and the amount of our anticipated liability considering the proportional liability and financial abilities of other responsible parties. Estimated liabilities are not discounted to present value, and environmental expenses are recorded primarily in operating expenses.

LEGAL MATTERS. In the ordinary course of business, we become party to lawsuits, administrative proceedings and governmental investigations. These matters may involve large or unspecified damages or penalties that may be sought from us and may require years to resolve. We record a liability related to a loss contingency attributable to such legal matters in other current liabilities or other noncurrent liabilities on our consolidated balance sheets, depending on the classification as current or noncurrent if we determine the loss to be both probable and estimable. The liability is recorded for an amount that is management’s best estimate of the loss, or when a best estimate cannot be made, the minimum loss amount of a range of possible outcomes.

ACQUISITIONS

We use the acquisition method of accounting for the recognition of assets acquired and liabilities assumed with acquisitions at their estimated fair values as of the date of acquisition, with the exception of the Acquisitions from Tesoro. As an entity under common control with Tesoro, we record the assets that we acquire from Tesoro on our consolidated balance sheet at Tesoro’s historical basis instead of fair value. Any excess consideration transferred over the estimated fair values of the identifiable net assets acquired from third parties is recorded as goodwill. While we use our best estimates and assumptions to measure the fair value of the identifiable assets acquired and liabilities assumed at the acquisition date, our estimates are inherently uncertain and subject to refinement. As a result, during the measurement period, not to exceed one year from the date of acquisition, any changes in the estimated fair values of the net assets recorded for the acquisitions will result in an adjustment to goodwill. Upon the conclusion of the measurement period or final determination of the values of assets acquired or liabilities assumed, whichever comes first, any subsequent adjustments are recorded to our consolidated statements of operations. Our acquisitions are discussed further in Note 2.

REVENUE RECOGNITION

The Partnership generates revenue by charging fees for gathering crude oil and produced water, gathering and processing natural gas as well as fees for terminalling, transporting and storing crude oil and refined products. Revenues are recognized as crude oil, natural gas and refined products are transported through, delivered by, or stored in our pipelines, terminals and storage facility assets and transported by our trucking operations. Processing revenues are generated under long-term contracts with fee-based or keep-whole agreements. Under our fee-based agreements, the amount of fee-based revenue we generate is based on the volumes of natural gas that we process at our processing complexes.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

The only historic revenues reflected in the financial statements of our Predecessors are amounts received from third-party use of our pipelines and terminals, and amounts received from Tesoro with respect to transportation regulated by the RCA on the refined products pipeline included in the West Coast Logistics Assets Acquisition. Tesoro was not charged fees for services rendered with respect to any terminalling, storage or pipeline transportation services, except as described above, prior to the Acquisitions from Tesoro, as the respective assets were operated as a component of Tesoro’s petroleum refining and marketing businesses.

The Partnership has several streams of revenue. Revenues are recognized as products are shipped through our pipelines and terminals. Billings to customers for obligations under their quarterly minimum revenue commitments (shortfall payments) are recorded as deferred revenue when they have the right and physical ability to receive future services for these billings. Some of our fee-based agreements provide for fixed demand charges, which are recognized as revenue pursuant to the contract terms. Revenue associated with shortfall payments is recognized at the earlier of (i) the customer receiving the services provided by these billings, (ii) the expiration of the period in which the customer is contractually allowed to receive the services, (iii) the determination that future services will not be required.

REIMBURSEMENTS

Pursuant to the Third Amended and Restated Omnibus Agreement (“Amended Omnibus Agreement”) and Carson Assets Indemnity Agreement, Tesoro reimburses the Partnership for pressure testing, required repairs and maintenance identified as a result of the first inspection of certain pipeline and tank assets subsequent to the Acquisitions from Tesoro, as well as maintenance projects identified in the Amended Omnibus Agreement for which the costs were not known at the date of the Acquisitions from Tesoro. These amounts are recorded as a reduction to operating expense within the category labeled imbalance settlement gains, net and reimbursements during the period the costs are incurred and were $17 million, $34 million and $26 million for the years ended December 31, 2016, 2015 and 2014, respectively.

In addition, Tesoro reimburses the Partnership for capital projects identified in the Amended Omnibus Agreement. These amounts are recorded as a capital contribution by affiliate and were $29 million, $22 million and $18 million for the years ended December 31, 2016, 2015 and 2014, respectively.

IMBALANCES

We experience volume gains and losses, which we sometimes refer to as imbalances, within our pipelines, terminals and storage facilities due to pressure and temperature changes, evaporation and variances in meter readings and in other measurement methods. On our crude oil gathering and transportation system in North Dakota and Montana (the “High Plains System”), we retain 0.20% of the crude oil shipped on our owned and operated common carrier pipelines in North Dakota and Montana and we bear any crude oil volume losses in excess of that amount. Under the Second Amended and Restated Master Terminalling Service Agreement with Tesoro, we retain 0.25% of the refined products we handle at certain of our terminals for Tesoro, and bear any refined product volume losses in excess of that amount. The value of any crude oil or refined product imbalance settlements resulting from these tariffs or contractual provisions is determined by using the monthly average market prices for the applicable commodity, less a specified discount. The Partnership measures volume losses annually for the terminals and pipelines in the Northwest Products System. We retain 0.125% of the distillates and 0.25% of the other refined products we handle at our terminals on the Northwest Products System and we bear any refined product volume losses in excess of those amounts. The value of any refined product losses is determined by using the annual average market price for the applicable commodity. Any settlements under tariffs or contractual provisions where we bear any crude oil or refined product volume losses in excess of amounts specified reduce our operating expenses in the period in which they are realized, to the extent they are within the loss allowance, and increase our operating expenses in such period to the extent they exceed the loss allowance. For all of other terminals, and under our other commercial agreements with Tesoro, we have no obligation to measure volume losses and have no liability for physical losses.

The consolidated balance sheets also include offsetting natural gas imbalance receivables or payables resulting from differences in gas volumes received by customers and gas volumes delivered to interstate pipelines. Natural gas volumes owed to or by TLLP that are subject to tariffs are valued at market index prices, as of the balance sheet dates, and are subject to cash settlement procedures. Other natural gas volumes owed to or by TLLP are valued at the our weighted average cost of natural gas as of the balance sheet dates and are settled in-kind.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

UNIT-BASED COMPENSATION

Our general partner provides unit-based compensation to officers and non-employee directors for the Partnership, which includes service and performance phantom unit awards. The fair value of our service phantom unit awards on the date of grant is equal to the market price of our common units. We estimate the grant date fair value of performance phantom unit awards using a Monte Carlo simulation at the inception of the award. We amortize the fair value over the vesting period using the straight-line method. The phantom unit awards are settled in TLLP common units. Expenses related to unit-based compensation are included in general and administrative expenses in our consolidated statements of operations. Total unit-based compensation expense totaled $6 million for both the years ended December 31, 2016 and 2015 and $2 million for the year ended December 31, 2014. During 2016, the long term incentive plan was amended and restated to make available an additional 1,000,000 common units for unit-based awards and to make certain other administrative changes to the plan document. The Partnership had 1,085,464 units available for future grants under the long term incentive plan at December 31, 2016.

NET EARNINGS PER LIMITED PARTNER UNIT

We use the two-class method when calculating the net earnings per unit applicable to limited partners, because we have more than one participating security. At December 31, 2016, our participating securities consist of common units, general partner units and incentive distribution rights (“IDRs”). Net earnings attributable to the Partnership is allocated between the limited and general partners in accordance with our partnership agreement. We base our calculation of net earnings per unit on the weighted-average number of common and subordinated limited partner units outstanding during the period.

Diluted net earnings per unit includes the effects of potentially dilutive units on our common units, which consist of unvested service and performance phantom units. Basic and diluted net earnings per unit applicable to subordinated limited partners was historically the same, as there were no potentially dilutive subordinated units outstanding. Distributions less than or greater than earnings are allocated in accordance with our partnership agreement.

NEW ACCOUNTING STANDARDS AND DISCLOSURES

REVENUE RECOGNITION. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-09, “Revenue from Contracts with Customers” (“ASU 2014-09”), and has since amended the standard with ASU 2015-14, “Revenue From Contracts with Customers: Deferral of the Effective Date,” ASU 2016-08, ”Revenue From Contracts with Customers: Principal versus Agent Considerations (Reporting Revenue Gross versus Net),” ASU 2016-10, “Revenue From Contracts with Customers: Identifying Performance Obligations and Licensing,” and ASU 2016-12, “Revenue From Contracts with Customers: Narrow-Scope Improvements and Practical Expedients.” These standards replace existing revenue recognition rules with a single comprehensive model to use in accounting for revenue arising from contracts with customers. We are required to adopt ASU 2014-09 on January 1, 2018.

We have been and continue to evaluate the impact of the standard’s revenue recognition model on our contracts with customers in the Gathering and Processing and Terminalling and Transportation segments. While we have made substantial progress in our review and documentation of the impact of the standard on our revenue agreements, we continue to assess the impact in certain other areas where industry consensus continues to be formed such as agreements with terms that include non-cash consideration, contributions in aid of construction, and tiered pricing structures. At this time, we are unable to estimate the full impact of the standard until the industry reaches a consensus on certain industry specific issues.

We are currently in the early stages of our implementation plan and are evaluating the impact of the standard on our business processes, accounting systems, controls and financial statement disclosures. We preliminarily expect to transition to the new standard under the modified retrospective transition method, whereby a cumulative effect adjustment is recognized upon adoption and the guidance is applied prospectively.

CONSOLIDATION. In February 2015, the FASB issued ASU 2015-02, “Amendments to the Consolidation Analysis” (“ASU 2015-02”). This standard modifies existing consolidation guidance for reporting organizations that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for interim and annual periods beginning after December 15, 2015, and requires either a retrospective or a modified retrospective approach to adoption. We adopted this guidance using the modified retrospective approach as of January 1, 2016 and performed the required reassessments outlined by the guidance. For further information on the results of the reassessments, refer to Note 6, Investments - Equity Method and Joint Ventures.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

BUSINESS COMBINATIONS. In September 2015, the FASB issued ASU 2015-16, “Simplifying the Accounting for Measurement-Period Adjustments” (“ASU 2015-16”). The standard requires an acquirer to recognize the cumulative impact of adjustments to provisional purchase price amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The standard also requires an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. ASU 2015-16 is effective for interim and annual periods beginning after December 15, 2015, and must be applied prospectively to adjustments that occur after the effective date. We adopted this guidance as of January 1, 2016, with no impact to our financial statements.

LEASES. In February 2016, the FASB issued ASU 2016-02, “Leases” (“ASU 2016-02”), which amends existing accounting standards for lease accounting and adds additional disclosures about leasing arrangements. Under the new guidance, lessees are required to recognize lease assets and lease liabilities on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either a finance lease or operating lease with the classification affecting the pattern of expense recognition in the income statement and presentation of the cash flows in the statement of cash flows. ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, and interim reporting periods within those annual reporting periods. Early adoption is permitted and modified retrospective application is required. We are still evaluating the impact of ASU 2016-02 on our financial statements.

SHARE-BASED COMPENSATION. In March 2016, the FASB issued ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting” (“ASU 2016-09”), which simplifies several aspects of the accounting for employee share-based payment transactions including accounting for income taxes, cash flow presentation of tax impacts, forfeitures, and liability versus equity accounting due to statutory tax withholding requirements. ASU 2016-09 is effective for interim and annual periods beginning after December 15, 2016, with early adoption permitted. As of January 1, 2016, we early adopted ASU 2016-09 and with respect to the guidance on forfeitures, we have elected to continue to estimate forfeitures on the date of grant to account for the estimated number of awards for which the requisite service period will not be rendered. The adoption of ASU 2016-09 had no impact on our financial statements.

CREDIT LOSSES. In June 2016, the FASB issued ASU 2016-13, “Measurement of Credit Losses on Financial Instruments” (“ASU 2016-13”), which amends guidance on the impairment of financial instruments. The ASU estimates credit losses based on expected losses, modifies the impairment model for available-for-sale debt securities and provides for a simplified accounting model for purchased financial assets with credit deterioration. ASU 2016-13 is effective for annual reporting periods beginning after December 15, 2019, and interim reporting periods within those annual reporting periods. Early adoption is permitted for annual reporting periods beginning after December 15, 2018. While we are still evaluating the impact of ASU 2016-13, we do not expect the adoption of this standard to have a material impact on our financial statements.

STATEMENT OF CASH FLOWS. In August 2016, the FASB issued ASU 2016-15, “Clarification of Certain Cash Receipts and Cash Payments” (“ASU 2016-15”), which eliminates the diversity in practice related to the classification of certain cash receipts and payments in the statement of cash flows, by adding or clarifying guidance on eight specific cash flow issues. ASU 2016-15 is effective for interim and annual reporting periods beginning after December 15, 2017, with early adoption permitted. The amendments in this update should be applied retrospectively to all periods presented, unless deemed impracticable, in which case, prospective application is permitted. We early adopted this standard retrospectively as of December 31, 2016, which had an immaterial impact on our financial statements.

DEFINITION OF A BUSINESS. In January 2017, the FASB issued ASU 2017-01, “Clarifying the Definition of a Business” (“ASU 2017-01”), which revises the definition of a business and assists in the evaluation of when a set of transferred assets and activities is a business. ASU 2017-01 is effective for interim and annual reporting periods beginning after December 15, 2017, and should be applied prospectively on or after the effective date. Early adoption is permitted under certain circumstances. At this time, we are evaluating the potential impact of this standard on our financial statements.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 2 – ACQUISITIONS

ACQUISITIONS FROM TESORO

NORTHERN CALIFORNIA TERMINALLING AND STORAGE ASSETS. Effective November 21, 2016, the Partnership acquired certain terminalling and storage assets located in Martinez, California from subsidiaries of Tesoro for a total consideration of $400 million, comprised of $360 million in cash financed with borrowings under our secured dropdown credit facility (the “Dropdown Credit Facility”), and the issuance of equity securities of the Partnership with a fair value of approximately $40 million. The Northern California Terminalling and Storage Assets include crude oil, feedstock, and refined product storage capacity at Tesoro’s Martinez Refinery along with the Avon marine terminal capable of handling feedstock and refined product throughput. The equity consideration was comprised of 860,933 units in the form of common units and 17,570 units in the form of general partner units.

ALASKA STORAGE AND TERMINALLING ASSETS. Effective July 1, 2016, the Partnership entered into an agreement to purchase certain terminalling and storage assets owned by Tesoro for total consideration of $444 million and was completed in two phases. On July 1, 2016, the Partnership completed the acquisition of the first phase consisting of tankage, related equipment and ancillary facilities used for the operations at Tesoro’s Kenai Refinery. The second phase was completed on September 16, 2016 and consisted of refined product terminals in Anchorage and Fairbanks. Consideration paid for the first phase was $266 million, comprised of approximately $240 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of 162,375 general partner units and 390,282 common units to Tesoro with a combined fair value of $26 million. Consideration paid for the second phase was $178 million, comprised of approximately $160 million in cash, financed with borrowings under the Dropdown Credit Facility, and the issuance of 20,440 general partner units and 358,712 common units to Tesoro with a combined fair value of $18 million.

LA STORAGE AND HANDLING ASSETS. On November 12, 2015, the Partnership purchased crude oil and refined product storage and pipeline assets in Los Angeles, California owned by subsidiaries of Tesoro Corporation, for a total consideration of $500 million. The Partnership acquired crude oil, feedstock, and refined product storage tank facility and a 50% fee interest in a 16-mile pipeline that transports jet fuel from Tesoro’s Los Angeles refinery to the Los Angeles International Airport. The acquisition price of $500 million included cash of approximately $250 million, funded in part from the unsecured term loan facility (the “Unsecured Term Loan Facility”), and the issuance of common and general partner units to Tesoro, valued at approximately $250 million.

WEST COAST LOGISTICS ASSETS. On June 23, 2014, we entered into an agreement with Tesoro to acquire certain terminalling and pipeline assets owned by Tesoro and two of its subsidiaries, Tesoro Refining & Marketing Company LLC and Tesoro Alaska Company LLC for total consideration of $270 million and was completed in two stages. The operations of the West Coast Logistics Assets are included in our Terminalling and Transportation segment. On July 1, 2014, the Partnership completed the acquisition of the first phase of the West Coast Logistics Assets in exchange for consideration of $241 million, comprised of approximately $214 million in cash, financed with borrowings on our secured revolving credit facility (the “Revolving Credit Facility”), the issuance of equity to Tesoro with a fair value of $27 million. The equity was comprised of 370,843 common units and 8,856 general partner units. The second phase was completed on September 30, 2014, upon receiving the required regulatory approval from the RCA, for cash consideration of $29 million, which was financed with borrowings on our Revolving Credit Facility. The assets consist of all of Tesoro’s membership interests in Tesoro Alaska Pipeline Company LLC, a wholly-owned subsidiary of Tesoro, which owns a refined products pipeline connecting Tesoro’s Kenai refinery to our terminals in Anchorage, Alaska.

In connection with all of the acquisitions above, Tesoro and TLLP entered into long-term, fee-based storage and throughput and use agreements. See Note 3 for additional information regarding commercial agreements and amendments to other agreements with related parties in connection with the acquisitions.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

OTHER ACQUISITIONS

NORTH DAKOTA GATHERING AND PROCESSING ASSETS. On November 21, 2016, the Partnership agreed to acquire crude oil, natural gas and produced water gathering systems and two natural gas processing facilities from Whiting Oil and Gas Corporation, GBK Investments, LLC and WBI Energy Midstream, LLC for total consideration of approximately $700 million funded with cash on-hand, which included the borrowings under our Revolving Credit Facility. The North Dakota Gathering and Processing Assets include crude oil, natural gas, and produced water gathering pipelines, natural gas processing and fractionation capacity in the Sanish and Pronghorn fields of the Williston Basin in North Dakota. The acquisition, which was subject to customary closing conditions including regulatory approval, closed January 1, 2017. Given the acquisition date, it was impracticable to provide an initial estimate of the fair value of identifiable assets acquired, residual goodwill or pro forma information. We expect to provide disclosures of the preliminary fair value of identified assets acquired and pro forma information, if material, in our interim condensed consolidated financial statements for the period ending March 31, 2017.

ROCKIES NATURAL GAS BUSINESS. On December 2, 2014, the Partnership acquired all of the limited liability company interests of QEPFS for an aggregate purchase price of approximately $2.5 billion, which includes environmental obligations, existing legal obligations and $230 million QEPM debt. QEPFS is the direct or indirect owner of assets related to, and entities engaged in, natural gas gathering, transportation and processing in or around the Green River Basin located in Wyoming and Colorado, the Uinta Basin located in eastern Utah, and the portion of the Williston Basin located in North Dakota. During 2015, TLLP recorded measurement period adjustments, which reduced goodwill by $34 million, after obtaining additional information regarding, among other things, asset valuations and liabilities assumed.

On July 22, 2015, TLLP and QEPM completed the transaction in which TLLP Merger Sub LLC merged with and into QEPM, with QEPM surviving the merger as a wholly-owned subsidiary of TLLP (the “QEPM Merger”). TLLP issued additional TLLP Common Units to QEPM unitholders as a result of the QEPM Merger. There was no impact to the purchase price allocation as a result of the QEPM Merger.

During the years ended December 31, 2015 and 2014, we incurred transaction costs of $2 million and $33 million, respectively, related to the Rockies Natural Gas Business Acquisition directly attributable to the transaction. These costs are included in general and administrative expenses and interest and financing costs, net in our consolidated statements of operations.

The unaudited pro forma condensed consolidated results of operations for the year ended December 31, 2014, are provided as if the Rockies Natural Gas Business Acquisition had been completed on January 1, 2014. The unaudited pro forma financial information reflects adjustments to exclude $8 million of nonrecurring accelerated amortization of certain QEPFS deferred issuance costs and the $33 million of transaction costs as a result of the Rockies Natural Gas Business Acquisition for the year ended December 31, 2014. Pro forma revenues, net earnings and net earnings attributable to partners were $936 million, $101 million and $106 million, respectively, for the year ended December 31, 2014. Pro forma basic and diluted net earnings per limited partner unit were both $0.77 per common unit and were both $1.13 per subordinated unit for the year ended December 31, 2014.

NOTE 3 – RELATED-PARTY TRANSACTIONS

COMMERCIAL AGREEMENTS

The Partnership has various long-term, fee-based commercial agreements with Tesoro, under which we provide pipeline transportation, trucking, terminal distribution and storage services to Tesoro, and Tesoro commits to provide us with minimum monthly throughput volumes of crude oil and refined products. If, in any calendar month, Tesoro fails to meet its minimum volume commitments under these agreements, it will be required to pay us a shortfall payment. These shortfall payments may be applied as a credit against any amounts due above their minimum volume commitments for up to three months after the shortfall occurs. Each of these agreements has fees that are indexed annually for inflation or, in certain circumstances, allows for a quarterly rate adjustment based on a comparison of competitive rates.



		December 31, 2016 \| 57



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

COMMERCIAL AGREEMENTS WITH TESORO



				Termination Provisions
Commercial Agreement	Initiation Date	Term	Renewals	Refinery Shutdown Notice Period (a)	Force Majeure
Transportation Agreement (High Plains System)	April 2011	10	2 x 5 years	12 months	TLLP can declare (unilateral)
Second Amended and Restated Master Terminalling Agreement	April 2011	10	2 x 5 years
Stockton Minimum Throughput Commitment (MTA supplement)	April 2011	10	2 x 5 years
Salt Lake City Storage Agreement	April 2011	10	2 x 5 years
Amended and Restated Transportation Services Agreement	April 2011	10	2 x 5 years
Amorco Terminal Use and Throughput Agreement (Martinez Marine)	April 2012	10	2 x 5 years
Amended Anacortes Track Use and Throughput Agreement	November 2012	10	2 x 5 years	N/A
Terminalling Services Agreement for Northwest Products System	June 2013	1	Year to year
Southern California Terminalling Services Agreement	June 2013	10	2 x 5 years
Carson Storage Services Agreement Amended	June 2013	10	2 x 5 years
Southern California Dedicated Storage Agreement	June 2013	10	2 x 5 years
Long Beach Storage Services Agreement	December 2013	10	2 x 5 years
Carson Coke Handling Service Agreement	December 2013	10	2 x 5 years
Long Beach Throughput Agreement (b)	December 2013	10	2 x 5 years
Transportation Services Agreement (SoCal Pipelines)	December 2013	10	2 x 5 years
Amended and Restated Long Beach Berth Access Use and Throughput Agreement	December 2013	10	2 x 5 years
BASH Storage - TRMC Tanks	April 2014	5	2 x 5 years
Terminalling Services Agreement - Martinez	July 2014	10	2 x 5 years
Terminalling Services Agreement - Nikiski	July 2014	10	2 x 5 years
Storage Services Agreement - Anacortes	July 2014	10	2 x 5 years
Martinez Dedicated LPG Storage Agreement	July 2014	10	2 x 5 years
THPP Reversal Open Season Northbound Commitment	September 2014	7	None
Tesoro Alaska Pipeline Throughput Agreement	September 2014	10	2 x 5 years
Transportation Services Agreement (LAR Short Haul Pipelines)	September 2014	10	2 x 5 years
Keep-Whole Commodity Fee Agreement	December 2014	5	1 year auto	90 days prior to expiration	Bilateral
Terminalling Services Agreement - Anacortes Rack	November 2015	10	2 x 5 years	N/A	TLLP can declare (unilateral)
Carson Tank Farm Storage Agreement	November 2015	10	2 x 5 years
Kenai Storage Services Agreement	July 2016	10	2 x 5 years
Alaska Terminalling Services Agreement	September 2016	10	2 x 5 years
Avon Marine Terminal Operating Agreement	November 2016	Effective date of sublease	None
Martinez Storage Services Agreement	November 2016	10	2 x 5 years
Asphalt and Propane Rack Loading Services Agreement	December 2016	10	2 x 5 years


(a)	Fixed minimum volumes remain in effect during routine turnarounds.


(b)	Agreement gives Tesoro the option to renew for two five-year terms, or Tesoro may modify the term of the agreements to a twenty-year term by providing notice in accordance with each agreement.

We charge fixed fees based on the total storage capacity of our tanks under several of our agreements with Tesoro. We recognized approximately $193 million, $105 million and $83 million of revenue under these agreements where TLLP was considered to be the lessor during the years ended December 31, 2016, 2015 and 2014, respectively. Committed minimum payments for each of the five years following December 31, 2016, are expected to be approximately $260 million to $268 million per year and an aggregate $890 million remaining after 2021.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

THIRD AMENDED AND RESTATED OMNIBUS AGREEMENT

The Partnership entered into an omnibus agreement with Tesoro at the closing of the TLLP initial public offering (“Initial Offering”). The agreement has been amended for each of the Acquisitions from Tesoro and was most recently amended on November 21, 2016, in connection with the acquisition of the Martinez Logistics Assets. The amendment increased the annual administrative fee payable by the Partnership to Tesoro under the Amended Omnibus Agreement to approximately $11 million as of December 31, 2016, for the provision of various general and administrative services, including executive management, legal, accounting, treasury, human resources, health, safety and environmental, information technology, certain insurance coverage, administration and other corporate services. In addition, the Partnership reimburses Tesoro for all other direct or allocated costs and expenses incurred by Tesoro or its affiliates on its behalf.

Under the Amended Omnibus Agreement, Tesoro indemnifies us for certain matters, including known environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and the subsequent acquisitions from Tesoro, with certain exceptions that are covered by the Carson Assets Indemnity Agreement. With respect to assets that we acquired from Tesoro, indemnification for unknown environmental and title liabilities is limited to pre-closing conditions identified prior to the earlier of the date that Tesoro no longer controls our general partner or five years after the date of closing. The indemnification under the Initial Offering for unknown environmental matters expired on April 26, 2016. Under the Amended Omnibus Agreement, the aggregate annual deductible for each type of liability (unknown environmental liabilities or title matters) is approximately $1 million as of December 31, 2016, before we are entitled to indemnification in any calendar year in consideration of Initial Offering assets and all subsequent Acquisitions from Tesoro, with the exception of the indemnifications for the acquisition of the six marketing and storage terminal facilities (the “Los Angeles Terminal Assets”) and the acquisition of the remaining logistics assets (the “Los Angeles Logistics Assets”) initially acquired by us as part of the Los Angeles acquisition in Southern California (the “Los Angeles Logistics Assets Acquisition”). In addition, with respect to the assets that we acquired from Tesoro, we have agreed to indemnify Tesoro for events and conditions associated with the ownership or operation of our assets that occur after the closing of the Initial Offering, and the subsequent Acquisitions from Tesoro, and for environmental liabilities related to our assets to the extent Tesoro is not required to indemnify us for such liabilities. See Note 10 for additional information regarding the Amended Omnibus Agreement.

CARSON ASSETS INDEMNITY AGREEMENT

The Partnership entered into the Carson Assets Indemnity Agreement with Tesoro at the closing of the Los Angeles Logistics Assets Acquisition effective December 6, 2013, establishing indemnification for certain matters including known and unknown environmental liabilities arising out of the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the respective acquisition dates.

Under the Carson Assets Indemnity Agreement, Tesoro retained responsibility for remediation of known environmental liabilities due to the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the respective acquisition dates, and has indemnified the Partnership for any losses incurred by the Partnership arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is limited to five years. However, with respect to Terminal 2 at the Long Beach marine terminal, which was included in the Los Angeles Logistics Assets Acquisition, the indemnification for unknown pre-closing remediation liabilities is limited to ten years. Indemnification of the Los Angeles Terminal Assets’ and the Los Angeles Logistics Assets’ environmental liabilities is not subject to a deductible. See Note 10 for additional information regarding the Carson Assets Indemnity Agreement.

KEEP-WHOLE COMMODITY FEE AGREEMENT

Effective December 2, 2014, following the completion of the Rockies Natural Gas Business Acquisition, we began processing gas for certain producers under keep-whole processing agreements. Under a keep-whole agreement, a producer transfers title to the NGLs produced during gas processing, and the processor, in exchange, delivers to the producer natural gas with a British Themal Unit content equivalent to the NGLs removed. The operating margin for these contracts is typically determined by the spread between NGLs sales prices and the price paid to purchase the replacement natural gas (“Shrink Gas”). At that time, TLLP entered into a five-year agreement with Tesoro, which transfers the commodity risk exposure associated with these keep-whole processing agreements from TLLP to Tesoro (the “Keep-Whole Commodity Agreement”). Under the Keep-Whole Commodity Agreement with Tesoro, Tesoro pays TLLP a processing fee for NGLs related to keep-whole agreements and delivers Shrink Gas to the producers on behalf of TLLP. TLLP pays Tesoro a marketing fee in exchange for assuming the commodity risk.

On February 1, 2016, the parties entered into the First Amendment to the Keep-Whole Commodity Agreement (the “Keep-Whole Amendment”) that adjusted the contract to provide for a tiered pricing structure for different NGL production levels. The



		December 31, 2016 \| 59



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Keep-Whole Amendment continues to provide for annual purchase orders setting forth service fees for the base and incremental volumes; however, the Keep-Whole Amendment provides that the service fees payable for incremental volumes of natural gas liquids above 315,000 gallons per day shall be calculated with reference to the costs of (i) processing, (ii) conditioning, (iii) handling, (iv) fractionation, (v) storage, truck and rail loading at the Blacks Fork Processing Complex, and (vi) pipeline transportation fees on the MAPL Pipeline System and fractionation fees at Mt. Belvieu, Texas for transportation and fractionation services provided to Processors by MAPL, Cedar Bayou Fractionators, and Enterprise Products Partners L.P. for natural gas liquids sold pursuant to the Keep-Whole Commodity Agreement. The pricing for both the base and incremental volumes are subject to revision each year.

SECONDMENT AND LOGISTICS SERVICES AGREEMENT

We entered into the Secondment and Logistics Services Agreement (the “Secondment Agreement”) with Tesoro to govern the provision of seconded employees to or from Tesoro, the Partnership, and its subsidiaries, as applicable. The Secondment Agreement, as amended as recently as November 2016, also governs the use of certain facilities of the parties by the various entities. The services to be provided by such seconded employees, along with the fees for such services, will be provided on the service schedules attached to the Secondment Agreement. Specialized services and the use of various facilities, along with the fees for such services, will be provided for in service orders to be executed by parties requesting and receiving the service. All fees to be paid pursuant to the Secondment Agreement are indexed for inflation. For the years ended December 31, 2016 and 2015, the Partnership charged Tesoro $5 million and $3 million, respectively, and Tesoro charged the Partnership $18 million and $8 million, respectively, pursuant to the agreement.

On December 2, 2014, the General Partner and certain of its indirect subsidiaries entered into Amendment No. 1 to the Secondment Agreement (the “Secondment Agreement Amendment”) with Tesoro, pursuant to which these entities joined as parties to the Secondment Agreement dated July 1, 2014, to provide for the secondment of employees to or from those entities and Tesoro.

On March 31, 2016 and November 21, 2016, the General Partner and certain of its indirect subsidiaries entered in Amendments No. 2 and No. 3, respectively to the Secondment Agreement with Tesoro. Under Amendment No.2, additional parties were added to the agreement. Under Amendment No. 3 the parties agree that either party may provide labor, materials, equipment and supplies to either Tesoro or TLLP, that such work may be provided by third parties under contract with one of the parties to the amendment and that the costs and expenses will be allocated to the parties that receive the benefits of such work.

SUMMARY OF AFFILIATE TRANSACTIONS

SUMMARY OF REVENUE AND EXPENSE TRANSACTIONS WITH TESORO, INCLUDING PREDECESSORS (in millions)



	Years Ended December 31,
	2016		2015		2014
Revenues	$	715	$	615	$	497
Operating expenses	166		135		111
Imbalance settlement gains, net and reimbursements from Tesoro (a)	24		42		43
General and administrative expenses	69		72		39

(a)

Includes net imbalance settlement gains of $7 million, $8 million and $17 million in the years ended December 31, 2016, 2015 and 2014, respectively. Also includes reimbursements primarily related to pressure testing and repairs and maintenance costs pursuant to the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement of $17 million, $34 million and $26 million in the years ended December 31, 2016, 2015 and 2014, respectively.

PREDECESSOR TRANSACTIONS. Related-party transactions of our Predecessors were settled through equity. The balance in receivables and accounts payable from affiliated companies represents the amount owed from or to Tesoro related to certain affiliate transactions. Our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment, with the exception of regulatory tariffs charged to Tesoro on the refined products pipeline included in the West Coast Logistics Assets Acquisition.

DISTRIBUTIONS. In accordance with our partnership agreement, our limited and general partner interests are entitled to receive quarterly distributions of available cash. We paid quarterly cash distributions to Tesoro, including IDRs, totaling $245 million, $148 million and $87 million in 2016, 2015 and 2014, respectively. On January 18, 2017, in accordance with our partnership



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

agreement, we announced the declaration of a quarterly cash distribution, based on the results of the fourth quarter of 2016, of $0.91 per unit, of which $77 million was paid to Tesoro on February 14, 2017 based on unitholders of record on February 3, 2017.

NOTE 4 – PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT BY SEGMENT (in millions)



	December 31,
	2016			2015
Gathering and Processing (a)	$	1,983		$	2,265
Terminalling and Transportation (b)	2,076			1,897
Property, Plant and Equipment, at Cost	4,059			4,162
Accumulated depreciation (a) (b)	(615		)	(481		)
Property, Plant and Equipment, Net	$	3,444		$	3,681


(a)	We recognized a decrease of $363 million to net property, plant and equipment as of January 1, 2016, as a result of the deconsolidation of RGS. See Note 6 for further discussion of the deconsolidation of RGS.


(b)	Assets owned by us for which we are the lessor under operating leases were $385 million and $252 million before accumulated depreciation of $111 million and $41 million as of December 31, 2016 and 2015, respectively.

NOTE 5 – ACQUIRED INTANGIBLES AND GOODWILL

ACQUIRED INTANGIBLES

The acquired intangible assets, net of accumulated amortization, was $947 million at December 31, 2016 consisting of customer relationships associated with the natural gas gathering and processing operations from the Rockies Natural Gas Business Acquisition. The value for the identified customer relationships consists of cash flows expected from existing contracts and future arrangements from the existing customer base. Accumulated amortization was $61 million and $32 million at December 31, 2016 and 2015, respectively. Amortization expense of acquired intangible assets was $29 million for both years ended December 31, 2016 and 2015. As of December 31, 2016, amortization expense is expected to be approximately $29 million per year through 2021.

GOODWILL

We had goodwill of $117 million and $130 million at December 31, 2016 and 2015, respectively. The deconsolidation of RGS, as further discussed in Note 6, reduced the Partnership’s consolidated goodwill by approximately $13 million.

For 2016, we elected to perform our annual goodwill impairment using a two-step quantitative assessment process on our goodwill of $117 million. As part of our two-step quantitative goodwill impairment process, we engaged a third party appraisal firm to assist in the determination of estimated fair value. This determination includes estimating the fair value using both the income and market approaches. The income approach requires management to estimate a number of factors, including projected future operating results, economic projections, anticipated future cash flows and discount rates. The market approach estimates fair value using comparable marketplace fair value data from within a comparable industry grouping. The determination of the fair value requires us to make significant estimates and assumptions. These estimates and assumptions primarily include, but are not limited to, the selection of appropriate peer group companies, control premiums appropriate for acquisitions in the industries in which we compete, the discount rates, terminal growth rates, and forecasts of revenue, operating income, depreciation and amortization and capital expenditures.

We determined that no impairment charges resulted from our November 1, 2016 goodwill impairment assessments. Furthermore, the fair value tested in step one of the goodwill impairment test exceeded the carrying value such that we were not required to perform step two. There were no impairments of goodwill during the years ended December 31, 2016, 2015 and 2014.



		December 31, 2016 \| 61



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 6 – INVESTMENTS - EQUITY METHOD AND JOINT VENTURES

For each of the following investments, we have the ability to exercise significant influence over each of these investments through our participation in the management committees, which make all significant decisions. However, since we have equal or proportionate influence over each committee as a joint interest partner and all significant decisions require the consent of the other investor(s) without regard to economic interest, we have determined that these entities should not be consolidated and apply the equity method of accounting with respect to our investments in each entity.

•

RGS. We have a 78% interest in RGS, which owns and operates the infrastructure that transports gas from certain fields to several re-delivery points in southwestern Wyoming, including natural gas processing facilities that are owned by us or a third party. Prior to 2016, we consolidated RGS, however, upon our reassessment performed in conjunction with the adoption of ASU 2015-02 as of January 1, 2016, we determined RGS represented a variable interest entity to us for which we are not the primary beneficiary. Under the limited liability company agreement, we do not have voting rights commensurate with our economic interest due to veto rights available to our partner in RGS. Certain business decisions, including, but not limited to, decisions with respect to significant expenditures or contractual commitments, annual budgets, material financings, dispositions of assets or amending the members’ gas servicing agreements, require unanimous approval of the members.


•	TRG. We own a 50% interest in TRG located in the southeastern Uinta Basin. TRG was formed with Ute Energy to transport natural gas gathered by UBFS and other third-party volumes to gas processing facilities. The Three Rivers Gathering system is primarily supported by long-term, fee-based gas gathering agreements with minimum volume commitments.


•	UBFS. We own a 38% interest in UBFS which owns and operates the natural gas gathering infrastructure located in the southeastern Uinta Basin and is supported by long-term, fee-based gas gathering agreements that contain firm throughput commitments, which generate fees whether or not the capacity is used, and is operated by us.

EQUITY METHOD INVESTMENTS (in millions)



	RGS			TRG				UBFS				Total
Balance at December 31, 2014	$	—		$	40			$	18			$	58
Investments	—			3			(c)	—			(c)	3
Equity in earnings	—			5				2				7
Distributions received	—			(6		)		(4		)		(10		)
Balance at December 31, 2015 (a)	—			42				16				58
Effect of deconsolidation (b)	295			—				—				295
Equity in earnings	8			2				3				13
Distributions received	(22		)	(4		)		(3		)		(29		)
Balance at December 31, 2016 (a)	$	281		$	40			$	16			$	337

(a)

The carrying amount of our investments in RGS, TRG and UBFS exceeded the underlying equity in net assets by $135 million, $16 million and $7 million, respectively, at December 31, 2016. The carrying amount of our investments in TRG and UBFS exceeded the underlying equity in net assets by $17 million and $8 million, respectively, at December 31, 2015. The carrying amounts of our investments that exceed the underlying equity in net assets are amortized over the useful life of the underlying fixed assets and included in equity in earnings (loss).


(b)	We recognized an increase of $295 million to equity method investments as of January 1, 2016 as a result of the deconsolidation of RGS. The carrying amount of our investment in RGS exceeded the underlying equity in net assets by $135 million at December 31, 2016


(c)	Includes the final fair value adjustment resulting from measurement period changes related to TLLP’s Rockies Natural Gas Business in 2015.



62 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 7 – OTHER CURRENT LIABILITIES

OTHER CURRENT LIABILITIES (in millions)



	December 31,
	2016		2015
Legal	$	—	$	21
Accrued environmental liabilities	17		21
Asset retirement obligation	6		1
Other	22		18
Total Other Current Liabilities	$	45	$	61

NOTE 8 – DEBT

DEBT BALANCE, NET OF UNAMORTIZED ISSUANCE COSTS (in millions)



	December 31,
	2016			2015
Revolving Credit Facility	$	330		$	305
Dropdown Credit Facility	—			—
Term Loan Facility	—			250
5.500% Senior Notes due 2019	500			500
5.875% Senior Notes due 2020 (a)	470			470
6.125% Senior Notes due 2021 (a)	800			550
6.250% Senior Notes due 2022	800			800
6.375% Senior Notes due 2024	450			—
5.250% Senior Notes due 2025	750			—
Capital lease obligations	9			8
Total Debt	4,109			2,883
Unamortized issuance costs (a)	(55		)	(39		)
Current maturities, net of unamortized issuance costs	(1		)	—
Debt, Net of Current Maturities and Unamortized Issuance Costs	$	4,053		$	2,844


(a)	Unamortized premiums of $4 million associated with these senior notes are included in unamortized issuance costs at both December 31, 2016 and 2015.

The aggregate maturities of our debt, including the principal payments of our capital lease obligations, for each of the five years following December 31, 2016 are approximately $1 million in 2017 and 2018, $501 million in 2019, $471 million in 2020 and $1.1 billion in 2021.

REVOLVING CREDIT FACILITY AND DROPDOWN CREDIT FACILITY

On January 29, 2016, we amended our existing secured Revolving Credit Facility to revise key terms related to pricing and financial covenants and lowered the aggregate available facility limit from $900 million to $600 million. As a result of this amendment, an immaterial amount of unamortized debt issuance costs were expensed. Additionally on January 29, 2016, we syndicated the $1.0 billion Dropdown Credit Facility. The primary use of proceeds under this facility will be to fund asset acquisitions. The terms, covenants and restrictions under this facility are substantially the same as with our amended secured Revolving Credit Facility. The total aggregate available facility limits for the Revolving Credit Facility and Dropdown Credit Facility totaled $1.6 billion at December 31, 2016. We are allowed to request the loan availability for both the Revolving Credit Facility and the Dropdown Credit Facility be increased up to an aggregate of $2.1 billion, subject to receiving increased commitments from lenders.

Our secured Revolving Credit Facility provided for total loan capacity of $600 million as of December 31, 2016. Borrowings are available under the secured Revolving Credit Facility up to the total loan availability of the facility. Our secured Revolving



		December 31, 2016 \| 63



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Credit Facility is non-recourse to Tesoro, except for TLGP, and is guaranteed by all of our consolidated subsidiaries with the exception of certain non-wholly owned subsidiaries acquired in the Rockies Natural Gas Business acquisition and secured by substantially all of our assets. As of December 31, 2016, there was $330 million in borrowings outstanding under the secured Revolving Credit Facility, which had unused credit availability of $270 million, or 45% the borrowing capacity. The weighted average interest rate for borrowings under our Revolving Credit Facility was 2.76% at December 31, 2016.

As of December 31, 2016, the Dropdown Credit Facility provided for total loan availability of $1.0 billion. We had no borrowings outstanding under the Dropdown Credit Facility, resulting in the full loan availability of the borrowing capacity as of December 31, 2016.

The Revolving Credit Facility and the Dropdown Credit Facility ratably share collateral comprised primarily of our property, plant and equipment and both facilities mature on January 29, 2021. In addition, upon an upgrade of our corporate family rating to investment grade from either Moody’s Investors Service or S&P Global Ratings, certain covenants and restrictions under each facility will automatically be eliminated or improved.

COVENANTS. The Revolving Credit Facility, the Dropdown Credit Facility and senior notes contain certain covenants that may, among other things, limit or restrict our ability (as well as those of our subsidiaries) to:


•	incur additional indebtedness and incur liens on assets to secure certain debt;


•	pay and make certain restricted payments;


•	make distributions from its subsidiaries;


•	dispose of assets in excess of an annual threshold amount;


•	in the case of our Revolving Credit Facility, make certain amendments, modifications or supplements to organization documents and material contracts;


•	in the case of the our Revolving Credit Facility, engage in certain business activities;


•	engage in certain mergers or consolidations and transfers of assets; and


•	enter into non-arm’s-length transactions with affiliates.

SENIOR NOTES EXCHANGE

On February 26, 2016, the Partnership commenced an offer to exchange (the “Exchange”) its existing unregistered 5.500% Senior Notes due 2019 (“2019 Notes”) and 6.250% Senior Notes due 2022 (“2022 Notes”) (together, “Unregistered Notes”) for an equal principal amount of senior notes due 2019 at 5.500% and senior notes due 2022 (the “Exchange Notes”) at 6.250%, respectively, that were registered under the Securities Act of 1933, as amended. The aforementioned rates of the Exchange Notes approximate the effective interest rate. On April 14, 2016, the Exchange was completed for all of the 2019 Notes and substantially all of the 2022 Notes. The terms of the Exchange Notes are identical in all material respects (including principal amount, interest rate, maturity and redemption rights) to the Unregistered Notes for which they were exchanged, except that the Exchange Notes generally are not subject to transfer restrictions. The Exchange fulfills all of the requirements of the registration rights agreements for the Unregistered Notes.

SENIOR NOTES

5.500% SENIOR NOTES DUE 2019. In October 2014, we completed a private offering of $1.3 billion aggregate principal amount of senior notes pursuant to a private placement transaction conducted under Rule 144A and Regulation S of the Securities Act of 1933, as amended. The $1.3 billion of aggregate principal senior notes, completed in a private offering (the “Senior Notes Offering”) consisted of $500 million of the 2019 Notes at 5.500%, which approximates the effective interest rate, and $800 million of 6.250% the 2022 Notes. The proceeds from the 2019 Notes were used to repay amounts outstanding under our Revolving Credit Facility related to the West Coast Logistics Assets Acquisition. The remaining net proceeds from the 2019 Notes were used to fund the Rockies Natural Gas Business Acquisition.

The 2019 Notes have no sinking fund requirements. We may redeem some or all of the 2019 Notes prior to September 15, 2019, at a make-whole price, and at par thereafter, plus accrued and unpaid interest. The 2019 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception of Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.



64 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

We agreed to complete a registered exchange offer to exchange the 2019 Notes for debt securities with substantially identical terms within 18 months of the closing date of the Senior Notes Offering. On April 14, 2016, we completed the Exchange of all of the 2019 Notes.

5.875% SENIOR NOTES DUE 2020. At December 31, 2016, we had $470 million of outstanding senior notes due in 2020 (the “2020 Notes”) at 5.875%, which approximates the effective interest rate, excluding unamortized premiums of $4 million. The 2020 Notes were issued in two offerings, the initial offering of $350 million of unregistered notes effective September 14, 2012 and the secondary offering of $250 million of unregistered notes effective December 17, 2013, which was issued at 102.25% of face value (together the “Unregistered Notes”). In July 2014, we completed an offer to exchange these Unregistered Notes for notes registered under the Securities Act of 1933, as amended (the “Exchange Notes”). In accordance with the terms of the Exchange Notes, each holder of the Unregistered Notes was entitled to receive the Exchange Notes, which are identical in all material respects to the Unregistered Notes (including principal amount, interest rate, maturity and redemption rights), except that the Exchange Notes generally are not subject to transfer restrictions. The exchange offer fulfills all of the requirements of the Registration Rights Agreement for the unregistered note.

The 2020 Notes have no sinking fund requirements. We may redeem some or all of the 2020 Notes at premiums equal to 2.938% through October 1, 2017; 1.469% from October 1, 2017 through October 1, 2018; and at par thereafter, plus accrued and unpaid interest. The 2020 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and any subsidiaries acquired with the Rockies Natural Gas Business Acquisition, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

In August 2014, we completed a public offering of 2.1 million common units representing limited partner interests, at a price of $67.47 per unit. We used the net proceeds for the redemption of $130 million of the 2020 Notes, and to pay accrued interest and premiums of $4 million and $7 million, respectively. TLGP reimbursed the payment of premiums, which was reflected as a contribution by TLGP as it relates to its ownership of our common units. The $7 million of premiums and $3 million of expenses of unamortized debt issuance costs were included in interest and financing costs, net.

6.125% SENIOR NOTES DUE 2021. In August 2013, we completed a private offering which were exchanged for registered notes of $550 million aggregate principal amount of senior notes due in 2021 (“the 2021 Notes”) at 6.125%, which approximates the effective interest rate. The proceeds of this offering were used to repay the amounts outstanding under our Revolving Credit Facility, which were used to fund a significant portion of the Los Angeles Terminal Assets Acquisition, and to pay a portion of the fees and expenses related to the offering of the 2021 Notes.

The 2021 Notes have no sinking fund requirements and we may redeem some or all of the notes at premiums equal to 4.594% through October 15, 2017; 3.063% from October 15, 2017 through October 15, 2018; 1.531% from October 15, 2018 through October 15, 2019; and at par thereafter, plus accrued and unpaid interest. The 2021 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer and any subsidiaries acquired with the Rockies Natural Gas Business Acquisition, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

In May 2016, we completed a registered offering of $250 million aggregate principal amount of senior notes due 2021 (“Supplemental 2021 Notes”) at 6.125%, which approximates the effective interest rate. We used the proceeds of the offering to repay amounts outstanding under the Dropdown Credit Facility.

The Supplemental 2021 Notes were issued under the same indenture governing the existing $550 million of the 2021 Notes and have the same terms. The Supplemental 2021 Notes have no sinking fund requirements and may be redeemed at premiums equal to 4.594% through October 15, 2017; 3.063% from October 15, 2017 through October 15, 2018; 1.531% from October 15, 2018 through October 15, 2019; and at par thereafter, plus accrued and unpaid interest. The Supplemental 2021 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

6.250% SENIOR NOTES DUE 2022. In October 2014, we issued $800 million aggregate principal amount of senior notes due in 2022 (the “2022 Notes”) at 6.250%, which approximates the effective interest rate. The proceeds from the 2022 Notes were used to fund a portion of the Rockies Natural Gas Business acquisition.

The 2022 Notes have no sinking fund requirements. We may redeem some or all of the 2022 Notes prior to October 15, 2018, at a make-whole price, plus any accrued and unpaid interest. On or after October 15, 2018, the 2022 Notes may be redeemed



		December 31, 2016 \| 65



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

at premiums equal to 3.125% through October 15, 2019; 1.563% from October 15, 2019 through October 15, 2020; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 106.25% of face value with proceeds from certain equity issuances through October 15, 2017. The 2022 Notes are unsecured and guaranteed by all of our consolidated subsidiaries, with the exception Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

We agreed to complete a registered exchange offer to exchange the 2022 Notes for debt securities with substantially identical terms within 18 months of the closing date of the Senior Notes Offering. On April 14, 2016, we completed the Exchange of substantially all of the 2022 Notes.

6.375% SENIOR NOTES DUE 2024. In May 2016, we completed a registered offering of $450 million aggregate principal amount of senior notes due in 2024 (the “2024 Notes”) at 6.375%, which approximates the effective interest rate. We used the proceeds of the offering to repay amounts outstanding under the Revolving Credit Facility and for general partnership purposes.

The 2024 Notes have no sinking fund requirements and we may redeem some or all of the 2024 Notes, prior to May 1, 2019, at a make-whole price plus accrued and unpaid interest, if any. On or after May 1, 2019, the 2024 Notes may be redeemed at premiums equal to 4.781% through May 1, 2020; 3.188% through May 1, 2021; 1.594% from May 1, 2021 through May 1, 2022; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 106.375% face value with proceeds from certain equity issuances through May 1, 2019. The 2024 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer, and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

5.250% SENIOR NOTES DUE 2025. On December 2, 2016, we completed a registered offering of $750 million aggregate principal amount of the senior notes due in 2025 (“the 2025 Notes”) at 5.250%, which approximates the effective interest rate. The proceeds from this offering were used to repay amounts outstanding under the Dropdown Credit Facility.

The 2025 Notes have no sinking fund requirements. We may redeem some or all of the 2025 Notes prior to January 15, 2021, at a make-whole price, plus any accrued and unpaid interest. On or after January 15, 2021, the 2025 Notes may be redeemed at premiums equal to 2.625% through January 15, 2022; 1.313% through January 15, 2023; and at par thereafter, plus accrued and unpaid interest. We will have the right to redeem up to 35% of the aggregate principal amount at 105.250% of face value with proceeds from certain equity issuances through January 15, 2020. The 2025 Notes are unsecured and guaranteed by all of our subsidiaries, except Tesoro Logistics Finance Corp., the co-issuer and are non-recourse to Tesoro, except for TLGP, and contain customary terms, events of default and covenants for an issuance of non-investment grade securities.

TERM LOAN

UNSECURED TERM LOAN FACILITY. In November 12, 2015, we entered into a $250 million the Unsecured Term Loan Facility to fund a portion of the LA Storage and Handling Assets from Tesoro. On February 3, 2016, we repaid the full amount of the Unsecured Term Loan Facility, including accrued interest, with proceeds drawn from the Dropdown Credit Facility. All commitments under the Unsecured Term Loan Facility were terminated effective with the repayment.

CAPITAL LEASE OBLIGATIONS

Our capital lease obligations relate to two leases of facilities used for trucking operations in North Dakota with initial terms of 15 years, with five-year renewal options and a right of way with an initial term of 31 years. The total cost of assets under capital leases was $11 million and $9 million for December 31, 2016 and 2015, respectively, and accumulated amortization was $2 million at both December 31, 2016 and 2015. We include the amortization of the cost of assets under capital leases in depreciation and amortization expenses in our consolidated statements of operations.



66 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

FUTURE MINIMUM ANNUAL LEASE PAYMENTS, INCLUDING INTEREST FOR THE CAPITAL LEASE (in millions)



	December 31, 2016
2017	$	1
2018	1
2019	1
2020	1
2021	1
Thereafter	7
Total minimum lease payments	12
Less amount representing interest	(3		)
Capital lease obligations	$	9

NOTE 9 – BENEFIT PLANS

Employees supporting our operations participate in the benefit plans and the employee thrift plan of Tesoro. Tesoro allocates expense to the Partnership for costs associated with the benefit plans based on the salaries of Tesoro’s employees that provide services to the Partnership as a percentage of total Tesoro salaries. The Predecessors were allocated expenses for costs associated with the benefit plans primarily based on the percentage of the Predecessors’ allocated salaries compared to Tesoro’s total salaries. Our portion of our Sponsor’s employee benefit plan expenses was $24 million, $23 million and $14 million for the years ended December 31, 2016, 2015 and 2014, respectively. These employee benefit plan expenses and the related payroll costs are included in operating expenses and general and administrative expenses in our consolidated statements of operations and include amounts allocated to the Predecessors.

NOTE 10 – COMMITMENTS AND CONTINGENCIES

OPERATING LEASES, PURCHASE OBLIGATIONS AND OTHER COMMITMENTS

FUTURE MINIMUM ANNUAL PAYMENTS APPLICABLE TO ALL NON-CANCELLABLE OPERATING LEASES AND PURCHASE OBLIGATIONS (in millions)



	Payments Due by Period
	2017		2018		2019		2020		2021		Thereafter		Total
Operating leases	$	16	$	12	$	11	$	9	$	8	$	70	$	126
Purchase obligations	86		86		86		87		49		—		394
Total	$	102	$	98	$	97	$	96	$	57	$	70	$	520

We have various cancellable and non-cancellable operating leases related to land, trucks, terminals, right-of-way permits and other operating facilities. In general, these leases have remaining primary terms up to 20 years and typically contain multiple renewal options. Total lease expense for all operating leases, including leases with a term of one month or less, was $11 million, $10 million and $8 million for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 8 for information related to our capital leases. See Note 3 for a discussion of revenue recognized under agreements where TLLP is considered the lessor.

Our purchase obligations include enforceable and legally binding service agreement commitments that meet any of the following criteria: (1) they are non-cancellable, (2) we would incur a penalty if the agreement was canceled, or (3) we must make specified minimum payments even if we do not take delivery of the contracted products or services. If we can unilaterally terminate the agreement simply by providing a certain number of days’ notice or by paying a termination fee, we have included the termination fee or the amount that would be paid over the notice period. Contracts that can be unilaterally terminated without a penalty are not included. Future purchase obligations primarily include fixed charges under the Amended Omnibus Agreement and the Secondment Agreement Amendment. Our Amended Omnibus Agreement remains in effect between the applicable parties until a change in control of the Partnership. As we are unable to estimate the termination of the omnibus agreement, we have included the fees for each of the five years following December 31, 2016 for the Amended Omnibus Agreement for disclosure purposes in the table above. Total expense under these service agreements was $192 million, $175 million and $117



		December 31, 2016 \| 67



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

million for the years ended December 31, 2016, 2015 and 2014, respectively. In addition to these purchase commitments, we also have minimum contractual capital spending commitments for approximately $82 million in 2017.

INDEMNIFICATION

Under the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement, Tesoro indemnifies us for certain matters, including environmental, title and tax matters associated with the ownership of our assets at or before the closing of the Initial Offering and the subsequent Acquisitions from Tesoro.

Under the Amended Omnibus Agreement, with respect to assets that we acquired from Tesoro, excluding the Los Angeles Terminal Assets and the Los Angeles Logistics Assets, indemnification for unknown environmental and title liabilities is limited to pre-closing conditions identified prior to the earlier of the date that Tesoro no longer controls our general partner or five years after the date of closing. The indemnification under the Initial Offering for unknown environmental matters expired on April 26, 2016. Under the Amended Omnibus Agreement, the aggregate annual deductible for each type of liability (unknown environmental liabilities or title matters) is approximately $1 million, as of December 31, 2016, before we are entitled to indemnification in any calendar year in consideration of the Initial Offering assets and all subsequent Acquisitions from Tesoro, with the exception of the Los Angeles Terminal Assets Acquisition and the Los Angeles Logistics Assets Acquisition. In addition, with respect to the assets that we acquired from Tesoro, we have agreed to indemnify Tesoro for events and conditions associated with the ownership or operation of our assets that occur after the closing of the Initial Offering, and the subsequent Acquisitions from Tesoro, and for environmental liabilities related to our assets to the extent Tesoro is not required to indemnify us for such liabilities.

Under the Carson Assets Indemnity Agreement, Tesoro retained responsibility for remediation of known environmental liabilities due to the use or operation of the Los Angeles Terminal Assets and the Los Angeles Logistics Assets prior to the acquisition dates, and has indemnified the Partnership for any losses incurred by the Partnership arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is limited to five years. However, with respect to Terminal 2 at the Long Beach marine terminal, which was included in the Los Angeles Logistics Assets Acquisition, the indemnification for unknown pre-closing remediation liabilities is limited to ten years. Indemnification of the Los Angeles Terminal Assets’ and the Los Angeles Logistics Assets’ environmental liabilities are not subject to a deductible.

OTHER CONTINGENCIES

In the ordinary course of business, we may become party to lawsuits, administrative proceedings and governmental investigations, including environmental, regulatory and other matters. The outcome of these matters cannot always be predicted accurately, but TLLP will accrue liabilities for these matters if the amount is probable and can be reasonably estimated. Contingencies arising after the closing of the Initial Offering from conditions existing before the Initial Offering, and the subsequent Acquisitions from Tesoro that have been identified after the closing of each transaction, will be recorded in accordance with the indemnification terms set forth in the Amended Omnibus Agreement and the Carson Assets Indemnity Agreement. Any contingencies arising from events after the Initial Offering, and the subsequent Acquisitions from Tesoro, will be the responsibility of TLLP.

ENVIRONMENTAL LIABILITIES

CHANGES IN OUR ENVIRONMENTAL LIABILITIES (in millions)



	Tioga Crude Oil Pipeline Release			Other Liabilities			Total
At December 31, 2014	$	25		$	7		$	32
Additions	24			1			25
Expenditures	(22		)	(2		)	(24		)
At December 31, 2015	27			6			33
Additions	7			1			8
Expenditures	(18		)	(1		)	(19		)
At December 31, 2016	$	16		$	6		$	22



68 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

UNRESOLVED MATTERS

TIOGA, NORTH DAKOTA CRUDE OIL PIPELINE RELEASE. In September 2013, the Partnership responded to the release of crude oil in a rural field northeast of Tioga, North Dakota (the “Crude Oil Pipeline Release”). The environmental liabilities related to the Crude Oil Pipeline Release include amounts estimated for remediation activities that will be conducted during the next few years to restore the site for agricultural use. We accrued an additional $7 million during the year ended December 31, 2016, to reflect improved scope definition and estimates, which resulted in an increase in the total estimated cost associated with the project. This incident was covered by our pollution liability insurance policy, subject to a $1 million deductible and a $25 million loss limit in place at that time. Pursuant to this policy, there were no insurance recovery receivables related to the Crude Oil Pipeline Release at both December 31, 2016 and 2015. The estimated remediation costs of $73 million exceeded our policy loss limit by $48 million as of December 31, 2016. We received no insurance proceeds for the year ended December 31, 2016, and $18 million and $7 million in reimbursement of costs incurred during the years ended December 31, 2015 and 2014, respectively.

On October 7, 2015, we received an offer to settle a Notice of Violation (“NOV”) from the North Dakota Department of Health (“NDDOH”). The NOV was issued on March 21, 2015, and alleges violations of water pollution regulations as a result of a release of crude oil that occurred near Tioga, North Dakota on our gathering and transportation pipeline system in September 2013. We are currently negotiating the settlement of this matter with the NDDOH. The ultimate resolution of the matter will not have a material impact on our liquidity, financial position, or results of operations.

XTO ENERGY INC. V. QEP FIELD SERVICES COMPANY. Prior to the Rockies Natural Gas Acquisition, XTO filed a complaint against QEPFS on January 30, 2014, asserting claims for breach of contract, breach of implied covenant of good faith and fair dealing, unjust enrichment and an accounting and declaratory judgment related to a 2010 gas processing agreement (the “XTO Agreement”). Tesoro Logistics processes XTO’s natural gas on a firm basis under the XTO Agreement. The XTO Agreement requires Tesoro Logistics to transport, fractionate and market XTO’s natural gas liquids derived from XTO’s processed gas. XTO is seeking monetary damages related to Tesoro Logistics allocation of charges related to XTO’s share of natural gas liquid transportation, fractionation and marketing costs associated with shortfalls in contractual firm processing volumes. Trial is set for July 2017.

In relation to $31 million of billed and unbilled amounts in our receivables that are subject to dispute with XTO as of December 31, 2016 as a result of this matter, we continue to believe that loss is not probable and estimable as we believe our allocation of applicable transportation, fractionation and marketing costs incurred by us related to minimum volume commitments made to us by XTO are permitted under the XTO Agreement and are consistent with industry standard. We have concluded continued recognition of revenue for charges allocated to XTO is appropriate under revenue recognition criteria including the fact that the costs being allocated are fixed and determinable and their collectability is deemed to be reasonably assured. Ultimate resolution of this matter is not expected to have a material impact on our liquidity or financial position, but the establishment of a reserve for uncollectible amounts subject to dispute may have a material impact on our results of operations in the period of establishment. A change in our ability to recognize revenue in future periods for the allocation of applicable transportation, fractionation, and marketing costs is not expected to have a material impact on our results of operations.

Other than described above, we do not have any other material outstanding lawsuits, administrative proceedings or governmental investigations. See current legal proceedings in Part I, Item 3.



		December 31, 2016 \| 69



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 11 – EQUITY

We had 68,926,453 common public units outstanding as of December 31, 2016. Additionally, Tesoro owned 34,055,042 of our common units, and 2,100,900 of our general partner units (the 2% general partner interest) as of December 31, 2016, which together constitutes a 34% ownership interest in us.

UNIT ISSUANCE. We closed a registered public offering of 6,325,000 common units representing limited partner interests, including the over-allotment option exercised by the underwriter for the purchase of an additional 825,000 common units, at a public offering price of $47.13 per unit on June 10, 2016. The net proceeds of $293 million were used for general partnership purposes, including debt repayment, acquisitions, capital expenditures and additions to working capital.

ATM PROGRAM. On June 25, 2014, we filed a prospectus supplement to our shelf registration statement filed with the SEC in 2012, authorizing the continuous issuance of up to an aggregate of $200 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “2014 ATM Program”). The 2014 ATM Program expired during the second quarter of 2015. During the years ended December 31, 2015 and 2014, we issued an aggregate of 819,513 and 199,400 common units under our 2014 ATM Program, generating proceeds of approximately $46 million and $14 million before issuance costs.

On August 24, 2015, we filed a prospectus supplement to our shelf registration statement filed with the Securities and Exchange Commission on August 6, 2015, authorizing the continuous issuance of up to an aggregate of $750 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program, referred to as our “2015 ATM Program”). During the years ended December 31, 2016 and 2015, we issued an aggregate of 1,492,637 and 1,093,483 common units, respectively, under our 2015 ATM Program, generating proceeds of approximately $72 million and $57 million, respectively, before issuance costs. The net proceeds from issuances under the 2015 and 2014 ATM Programs were used for general partnership purposes, including debt repayment, acquisitions, capital expenditures and additions to working capital.

ISSUANCE OF ADDITIONAL SECURITIES. Our partnership agreement authorizes us to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders. Costs associated with the issuance of securities are allocated to all unitholders’ capital accounts based on their ownership interest at the time of issuance.

NET EARNINGS PER UNIT. Our partnership agreement contains provisions for the allocation of net earnings and loss to the unitholders and the general partner. For purposes of maintaining partner capital accounts, the partnership agreement specifies that items of income and loss will be allocated among the partners in accordance with their respective percentage interest. Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions fully allocated to the general partner and any special allocations.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NET EARNINGS PER UNIT (in millions, except per unit amounts)



	Years Ended December 31,
	2016			2015			2014
Net earnings	$	315		$	249		$	56
Net earnings attributable to noncontrolling interest	—			(20		)	(3		)
Special allocation of net earnings (“Special Allocation”) (a)	3			—			7
Net earnings, excluding noncontrolling interest and including special allocations	318			229			60
General partner’s distributions	(10		)	(6		)	(5		)
General partner’s IDRs (b)	(148		)	(69		)	(41		)
Limited partners’ distributions on common units	(344		)	(259		)	(157		)
Limited partner’s distributions on subordinated units (c)	—			—			(14		)
Distributions greater than earnings	$	(184	)	$	(105	)	$	(157	)
General partner’s earnings:
Distributions	$	10		$	6		$	5
General partners IDRs (b)	148			69			41
Allocation of distributions greater than earnings (d)	(27		)	(44		)	(49		)
Total general partner’s earnings (loss)	$	131		$	31		$	(3	)
Limited partners’ earnings on common units:
Distributions	$	344		$	259		$	157
Special Allocation	(3		)	—			(7		)
Allocation of distributions greater than earnings	(157		)	(61		)	(98		)
Total limited partners’ earnings on common units	$	184		$	198		$	52
Limited partner’s earnings on subordinated units (c):
Distributions	$	—		$	—		$	14
Allocation of distributions greater than earnings	—			—			(10		)
Total limited partner’s earnings on subordinated units	$	—		$	—		$	4
Weighted average limited partner units outstanding:
Common units - basic	98.2			84.7			54.2
Common unit equivalents	—			0.1			—
Common units - diluted	98.2			84.8			54.2
Subordinated units - basic and diluted (c)	—			—			5.6
Net earnings per limited partner unit:
Common - basic	$	1.87		$	2.33		$	0.96
Common - diluted	$	1.87		$	2.33		$	0.96
Subordinated - basic and diluted	$	—		$	—		$	0.62

(a)

Normal allocations according to percentage interests are made after giving effect, if any, to priority income allocations in an amount equal to incentive cash distributions fully allocated to the general partner and any special allocations. The adjustment reflects the special allocation to common units held by TLGP for the interest incurred in connection with borrowings on the Dropdown Credit Facility in lieu of using cash on hand to fund the Alaska Storage and Terminalling Assets acquisition during the year ended December 31, 2016.


(b)	IDRs entitle the general partner to receive increasing percentages, up to 50%, of quarterly distributions in excess of $0.3881 per unit per quarter. The amount above reflects earnings distributed to our general partner net of $10 million of IDRs for the year ended December 31, 2015, waived by TLGP.


(c)	On May 16, 2014, the subordinated units were converted into common units on a one-for-one basis and thereafter participate on terms equal with all other common units in distributions of available cash. Distributions and the Partnership’s net earnings were allocated to the subordinated units through May 15, 2014.


(d)	We have revised the historical allocation of general partner earnings to include the Predecessors’ losses of $24 million, $43 million and $46 million for the years ended December 31, 2016, 2015 and 2014, respectively.



		December 31, 2016 \| 71



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

ALLOCATION OF THE GENERAL PARTNER’S INTEREST IN NET EARNINGS (in millions, except percentage of ownership interest)



	Years Ended December 31,
	2016			2015			2014
Net earnings attributable to partners	$	339		$	272		$	99
General partner’s IDRs	(148		)	(69		)	(41		)
Special Allocation	3			—			7
Net earnings available to partners	$	194		$	203		$	65
General partner’s ownership interest	2.0		%	2.0		%	2.0		%
General partner’s allocated interest in net earnings	$	4		$	4		$	1
General partner’s IDRs	148			69			41
Allocation of Predecessors’ impact to general partner interest	(24		)	(43		)	(46		)
Total general partner’s interest in net earnings (loss)	$	128		$	30		$	(4	)

CHANGES IN THE NUMBER OF UNITS OUTSTANDING (in million units)



	Common	Subordinated		General Partner	Total
At December 31, 2013	39.1	15.3		1.1	55.5
Issuances under ATM Program	0.2	—		—	0.2
Conversion in May 2014 of Tesoro’s subordinated units to common units	15.3	(15.3	)	—	—
Issuance in July 2014 in connection with the West Coast Logistics Assets acquisition	0.3	—		—	0.3
Issuance in August 2014 used primarily to redeem a portion of our 5.875% Senior Notes due 2020	2.1	—		—	2.1
Issuance in October 2014 to fund the Rockies Natural Gas Business Acquisition	23.0	—		0.5	23.5
Unit-based compensation awards	0.1	—		—	0.1
At December 31, 2014	80.1	—		1.6	81.7
Issuances under ATM Program	1.9	—		—	1.9
Issuance in July 2015 to effect the QEPM Merger	7.1	—		—	7.1
Issuance in November 2015 in connection with the LA Storage and Handling Assets acquisition	4.3	—		0.3	4.6
Unit-based compensation awards	0.1	—		—	0.1
At December 31, 2015	93.5	—		1.9	95.4
Issuances under ATM Program	1.4	—		—	1.4
Issuance of units in June 2016 for cash (a)	6.3	—		—	6.3
Issuance in July 2016 in connection with the Alaska Storage and Terminalling Assets acquisition (b)	0.4	—		0.2	0.6
Issuance in September 2016 in connection with the Alaska Storage and Terminalling Assets acquisition (b)	0.4	—		—	0.4
Issuance in November 2016 in connection with the Northern California Terminalling and Storage Assets acquisition (c)	0.9	—		—	0.9
Unit-based compensation awards	0.1	—		—	0.1
At December 31, 2016	103.0	—		2.1	105.1


(a)	In June 2016, we issued common units representing limited partner interests in a registered public offering, including the over-allotment option exercised by the underwriter for the purchase of common units.


(b)	On July 1 and September 16, 2016, we issued general partner and common units to Tesoro and TLGP in connection with the completion of the Alaska Storage and Terminalling Assets acquisition discussed in Note 2.


(c)	On November 21, 2016, we issued common units to Tesoro and TLGP in connection with the Northern California Terminalling and Storage Assets acquisition discussed in Note 2.



72 \| Tesoro Logistics LP



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

INCENTIVE DISTRIBUTION RIGHTS. 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 total 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. For illustrative purposes, the percentage interests set forth below for our general partner assume that there are no arrearages on common units, our general partner has contributed any additional capital necessary to maintain its 2% general partner interest and our general partner owns all of the IDRs.

PERCENTAGE ALLOCATION FOR INCENTIVE DISTRIBUTION RIGHTS



	Total quarterly distribution per unit target amount	Marginal percentage interest in distributions
	Total quarterly distribution per unit target amount	Unitholders	General Partner	Incentive Distribution Rights
Minimum Quarterly Distribution	$0.337500	98%	2%	—
First Target Distribution	Above $0.337500 up to $0.388125	98%	2%	—
Second Target Distribution	Above $0.388125 up to $0.421875	85%	2%	13%
Third Target Distribution	Above $0.421875 up to $0.506250	75%	2%	23%
Thereafter	Above $0.506250	50%	2%	48%

In connection with the North Dakota Gathering and Processing Assets acquisition, our general partner agreed to ratably reduce its quarterly distributions with respect to incentive distribution rights by $100 million with respect to distributions during 2017 and 2018.

DISTRIBUTIONS FOR ACQUISITIONS. Distributions to unitholders and general partner include $760 million, $250 million, and $243 million in cash payments for acquisitions from Tesoro during 2016, 2015 and 2014, respectively. As an entity under common control with Tesoro, we record the assets that we acquire from Tesoro in our consolidated balance sheets at Tesoro’s historical book value instead of fair value, and any excess of amounts paid over the historical book value of the assets acquired from Tesoro is recorded within equity. As a result of this accounting treatment, these transactions resulted in net decreases of $443 million, $211 million and $214 million in our equity balance during 2016, 2015 and 2014, respectively.

CASH DISTRIBUTIONS. Our partnership agreement, as amended, sets forth the calculation to be used to determine the amount and priority of cash distributions that the limited partner unitholders and general partner will receive. On January 18, 2017, in accordance with our partnership agreement, we announced the declaration of a quarterly cash distribution, based on the results of the fourth quarter of 2016, totaling $140 million, or $0.910 per limited partner unit. This distribution was paid on February 14, 2017 to unitholders of record on February 3, 2017.



		December 31, 2016 \| 73



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TOTAL QUARTERLY CASH DISTRIBUTIONS TO GENERAL AND LIMITED PARTNERS (in millions)



	Years Ended December 31,
	2016 (a)			2015 (a)			2014 (a)
General partner’s distributions:
General partner’s distributions	$	(10	)	$	(6	)	$	(5	)
General partner’s IDRs (b)	(148		)	(69		)	(41		)
Total general partner’s distributions	$	(158	)	$	(75	)	$	(46	)

Limited partners’ distributions:
Common	$	(344	)	$	(259	)	$	(157	)
Subordinated	—			—			(14		)
Total limited partners’ distributions	(344		)	(259		)	(171		)
Total Cash Distributions	$	(502	)	$	(334	)	$	(217	)


(a)	Our distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions are earned.


(b)	In connection with the Rockies Natural Gas Business Acquisition, our general partner waived its right to $10 million of general partner distributions with respect to IDRs during 2015.

NOTE 12 – SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental disclosure of cash activities includes interest paid, net of capitalized interest, of $165 million, $137 million and $73 million for the years ended December 31, 2016, 2015 and 2014, respectively.

SUPPLEMENTAL DISCLOSURE OF NON-CASH INVESTING AND FINANCING ACTIVITIES (in millions)



	Years Ended December 31,
	2016		2015		2014
Capital expenditures included in accounts payable at period end	$	30	$	54	$	50
Capital expenditures included in affiliate payable at period end	8		—		17
Capital leases and other	2		—		4
Predecessors’ net liabilities not assumed by Tesoro Logistics LP	22		3		1
Receivable from affiliate for capital expenditures	4		6		3



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 13 – OPERATING SEGMENTS

We changed our operating segment presentation in the first quarter of 2017 to reflect our expanded gathering and processing assets and operations and how our chief operating decision maker (“CODM”) manages our business. With the completion of the North Dakota Gathering and Processing Assets acquisition on January 1, 2017, our gathering and processing assets and operations expanded significantly and enhanced our ability to offer integrated gathering and processing services to our customers. Given the business’s focus on providing integrated services along with the revised reporting structure implemented by management to assess performance and make resource allocation decisions, we have determined our operating segments, which are the same for reporting purposes, are the (i) Gathering and Processing segment and (ii) Terminalling and Transportation segment. The Gathering and Processing segment information has been recast to reflect our current presentation. There were no changes to the categorization of assets within our Terminalling and Transportation segment.

Our Gathering and Processing segment consists of:


•	gathering systems including crude oil and natural gas pipeline gathering systems in the Bakken Region and the Green River Basin, Uinta Basin and Vermillion Basin in the Rockies Region, including:


•	the High Plains System;


•	the Williston Gathering System, which consists of a crude oil and natural gas gathering system located in the Williston Basin, North Dakota;


•	the Uinta Basin Gathering System, which consists of natural gas gathering systems and compression assets located in northeastern Utah;


•	the Green River System, which consists of an integrated natural gas gathering and transportation system;


•	the Vermillion Gathering System, which consists of natural gas gathering and compression assets located in Southern Wyoming, northwest Colorado and northeast Utah; and


•	equity method investments, which operate gathering pipeline and gas compression assets and transports natural gas to our natural gas processing facilities, located in the Uinta Basin.


•	gas processing and fractionation complexes, including:


•	the Vermillion processing complex;


•	the Uinta Basin processing complex;


•	the Blacks Fork processing complex fractionation facility; and


•	the Emigrant Trail processing complex.

Our Terminalling and Transportation segment consists of:


•	crude oil and refined products terminals and storage facilities in the western and midwestern U.S. that are supplied by Tesoro-owned and third-party pipelines, trucks and barges;


•	marine terminals in California that load and unload vessels;


•	pipelines, which transport products and crude oil from Tesoro’s refineries to nearby facilities in Salt Lake City and Los Angeles and a 50% fee interest in a pipeline that transports jet fuel from Tesoro’s Los Angeles refinery to the Los Angeles International Airport;


•	a regulated common carrier products pipeline and a jet fuel pipeline to the Salt Lake City International Airport


•	a rail-car unloading facility in Washington;


•	a petroleum coke handling and storage facility in Los Angeles; and


•	a regulated common carrier refined products pipeline system

Our revenues are generated from commercial agreements we have entered into with Tesoro, under which Tesoro pays us fees, and from third-party contracts for gathering crude oil and gathering and processing natural gas and distributing, transporting



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

and storing crude oil, refined products, natural gas and NGLs. The commercial agreements with Tesoro are described in Note 3. We do not have any foreign operations.

The operating segments adhere to the accounting polices used for our consolidated financial statements, as described in Note 1. Our operating segments are strategic business units that offer different services in different geographical locations. We evaluate the performance of each segment based on its respective operating income. Certain general and administrative expenses and interest and financing costs are excluded from segment operating income as they are not directly attributable to a specific operating segment. Identifiable assets are those used by the segment, whereas other assets are principally cash, deposits and other assets that are not associated with a specific operating segment.

SEGMENT INFORMATION RELATING TO CONTINUING OPERATIONS (in millions)



	Years Ended December 31,
	2016			2015			2014
Revenues
Gathering and Processing:
NGL sales	$	103		$	99		$	7
Gas gathering and processing	264			274			17
Crude oil and water gathering	133			123			66
Pass-thru and other revenue	115			121			68
Total Gathering and Processing Revenue	615			617			158
Terminalling and Transportation: (a)
Terminalling revenues	480			377			333
Pipeline transportation revenues	125			118			109
Total Terminalling and Transportation Revenue	605			495			442
Total Segment Revenues	$	1,220		$	1,112		$	600
Segment Operating Income
Gathering and Processing	$	218		$	217		$	49
Terminalling and Transportation	296			203			149
Total Segment Operating Income	514			420			198
Unallocated general and administrative expenses	(27		)	(27		)	(34		)
Interest and financing costs, net	(191		)	(150		)	(109		)
Equity in earnings of equity method investments	13			7			1
Other Income, net	6			—			—
Earnings Before Income Taxes	$	315		$	250		$	56

Depreciation and Amortization Expense
Gathering and Processing	$	107		$	111		$	15
Terminalling and Transportation	83			76			70
Total Depreciation and Amortization Expense	$	190		$	187		$	85

Capital Expenditures
Gathering and Processing	$	119		$	228		$	160
Terminalling and Transportation	154			158			112
Total Capital Expenditures	$	273		$	386		$	272


(a)	Our Predecessors did not record revenue for transactions with Tesoro in the Terminalling and Transportation segment for assets acquired in the Acquisitions from Tesoro prior to the effective date of each acquisition, except for the RCA tariffs charged to Tesoro on the refined products pipeline included in the acquisition of the West Coast Logistics Assets.



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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

TOTAL IDENTIFIABLE ASSETS BY OPERATING SEGMENT (in millions)



	December 31,
	2016		2015
Identifiable Assets
Gathering and Processing	$	3,392	$	3,469
Terminalling and Transportation	1,768		1,641
Other (a)	700		21
Total Identifiable Assets	$	5,860	$	5,131


(a)	Other consists mainly of $688 million in cash and cash equivalents as of December 31, 2016, which was used to fund the acquisition of the North Dakota Gathering and Processing Assets on January 1, 2017.

NOTE 14 – QUARTERLY FINANCIAL DATA (UNAUDITED)



	Quarters
	First		Second		Third		Fourth		Total Year
2016	(In millions, except per unit amounts)
Revenues	$	300	$	293	$	308	$	319	$	1,220
Operating expenses	117		112		112		128		469
Operating income	119		118		127		123		487
Net earnings	85		76		81		73		315
Limited partners' interest in net earnings	60		47		48		32		187
Net earnings per limited partner unit (a):
Common - basic	$	0.64	$	0.48	$	0.46	$	0.31	$	1.87
Common - diluted	$	0.64	$	0.48	$	0.46	$	0.31	$	1.87
2015
Revenues	$	263	$	275	$	282	$	292	$	1,112
Operating expenses	101		115		117		135		468
Operating income	99		97		100		97		393
Net earnings	65		60		65		59		249
Limited partners' interest in net earnings	50		49		54		46		199
Net earnings per limited partner unit (a):
Common - basic	$	0.63	$	0.60	$	0.62	$	0.49	$	2.33
Common - diluted	$	0.63	$	0.60	$	0.62	$	0.49	$	2.33


(a)	The sum of four quarters may not equal annual results due to rounding or the quarterly number of units outstanding.



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