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 Tesoro Logistics LP, its subsidiaries and its general partner.

The following information concerning our business description, results of operations and financial condition should be read in conjunction with our combined consolidated financial statements contained in this Form 8-K.

Those statements in this section that are not historical in nature should be deemed forward-looking statements that are inherently uncertain. See “Important Information Regarding Forward-Looking Statements” section for a discussion of the factors that could cause actual results to differ materially from those projected in these statements.

BUSINESS STRATEGY AND OVERVIEW

We are a leading full-service logistics company operating primarily in the western and mid-continent regions of the United States. We own and operate networks of over 3,500 miles of crude oil, refined products and natural gas pipelines and 29 crude oil and refined products truck and marine terminals that have over 15 million barrels of storage capacity. In addition, we own and operate four natural gas processing complexes and one fractionation facility.

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 are generally not exposed to commodity price risk with respect to any of the crude oil, natural gas, NGLs or refined products that we handle, with the exception of a nominal amount of condensate. 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 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, through their effects on our customers’ operations, these risks indirectly influence our activities and results of operations over the long term.

Strategy and Goals

Our primary business objectives are to maintain 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:

• focus on opportunities to provide committed fee-based logistics services to Tesoro and third parties;

• evaluate investment opportunities that may arise from the growth of Tesoro’s refining and marketing business or from increased third-party activity to make capital investments to expand our existing asset base;

• pursue accretive acquisitions of complementary assets from Tesoro as well as third parties; and

• seek to enhance the profitability of our existing assets by pursuing opportunities to add Tesoro and third-party volumes, improve operating efficiencies and increase utilization.

We have been implementing our strategy and goals discussed above, allowing us to steadily increase our cash flow available to be distributed to unitholders (“Distributable Cash Flow”) and to increase our distributions by 17% over the last year.

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Relative to these goals, in 2015, we implemented this strategy and have completed or announced plans to:

• expand our assets on our gathering and transportation system, located in the Bakken Region (the “High Plains System”) in support of growing third-party demand for transportation services and Tesoro’s demand for Bakken crude oil in the mid-continent and west coast refining systems, including:

◦ further expanding capacity and capabilities of our High Plains Pipeline;

◦ expanding our gathering footprint in the Bakken Shale/Williston Basin area of North Dakota and Montana (the “Bakken Region”), including crude oil, natural gas and water, to enhance and improve overall basin logistics efficiencies;

◦ adding other origin and destination points on the High Plains System to increase volumes; and

◦ improving the utilization of our proprietary truck fleet, which should generate cost and operating efficiencies.

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

• optimize Tesoro volumes and grow third-party volumes at our terminalling and transportation assets;

• expand and optimize our natural gas gathering and processing assets;

• completed the Connolly Gathering System major growth project, which has a capacity of approximately 60 Mbpd;

• completed the construction of a new light products truck rack at the site of the existing Anacortes terminal, which has a capacity of 20 Mbpd; and

• closed the acquisition of crude oil and refined product storage and pipeline assets in Los Angeles, California (the "LA Storage and Handling Assets") owned by subsidiaries of Tesoro, for a total consideration of $500 million.

Current Market Developments

For nearly 18 months, the spot prices of the commodities that we handle, including crude oil, natural gas, natural gas liquids and refined products, have declined, due in part to the rapid growth of global supplies in excess of global demand growth of these commodities. A weakened and volatile commodity price environment has created challenges for crude oil and natural gas producers who have modified their drilling and production plans. The U.S. oil and gas drilling rig count has declined while at the same time, improved drilling techniques have increased production per well. Lower retail prices and improved economic conditions have led to 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, is expected to have a minimal impact on our business in the short term. We continue to monitor the impact of these changes in market prices and fundamentals on our business in the western United States, including values recognized in connection with the acquired QEP Field Services (“Rockies Natural Gas Business”). In the crude oil and natural gas production basins where we operate, continued drilling for new wells is potentially not economic for producers to continue at sustained very low commodity prices. Currently, we believe our diversified portfolios of businesses as well as our customers’ minimum volume commitments are sufficient to continue to meet our goals and objectives outlined above. However, if challenging market conditions for producers persist for a sustained period of time, our customer’s financial condition could deteriorate causing non-payment, their potential bankruptcy and project deferrals.

Developments and Acquisitions

North Dakota Gathering and Processing Assets Acquisition. 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 (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 MMcf per day of natural gas processing capacity and 18,700 barrels per day ("bpd") 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 assets are well utilized based on current production levels and provide organic expansion opportunities that support continued drilling in existing well locations with attractive production economics. The acquisition, which is subject to customary closing conditions including regulatory approval, is anticipated to close early in the first quarter of 2017.

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Northern California Terminalling and Storage Assets. Effective November 21, 2016, the Partnership entered into an agreement to acquire terminalling and storage assets located in Martinez, California (the “Northern California Terminalling and Storage Assets”) from subsidiaries of Tesoro for a total consideration of $400 million, comprised of $360 million in cash financed with borrowings under the Partnership’s secured dropdown credit facility (“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 5.5 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 35,000 bpd of feedstock and refined product throughput. In connection with the acquisition, Tesoro and TLLP entered into long-term, fee-based storage and throughput and use agreements, which are expected to provide stable cash flows to TLLP.

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 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 (together, the “Alaska Storage and Terminalling Assets”). Consideration paid for the first phase was $266 million, comprised of approximately $240 million in cash, financed with borrowings under our secured 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.

To reflect the results of the Predecessor, operating and maintenance expenses were recasted to include additional expense of $4 million, $5 million, and $4 million during the years ended December 31, 2015, 2014 and 2013, respectively. Depreciation and amortization expenses were recasted to include an additional $1 million during each of the years ended December 31, 2015 and 2014 and $2 million during the year ended December 31, 2013.

Los Angeles Refinery Storage and Handling Assets. On November 12, 2015, we closed on the acquisition of the LA Storage and Handling Assets owned by subsidiaries of Tesoro, for a total consideration of $500 million. We acquired 97 crude oil, feedstock and refined product storage tanks with combined capacity of 6.6 million barrels 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.

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 gathering pipeline and pipeline transportation, crude oil trucking, terminalling, and processing), (2) operating and maintenance expenses and (3) certain other financial measures as discussed further in “Non-GAAP Financial Measures” below, including earnings attributable to partners before interest, income taxes, depreciation and amortization expenses (“EBITDA”) and Distributable Cash Flow.

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 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.

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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 and Maintenance Expenses

We manage our operating and maintenance 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 and maintenance expenses are also affected by the imbalance gain and loss provisions in our active published tariffs and in our commercial agreements with Tesoro. On our High Plains System, we retain 0.20% of the crude oil shipped on the High Plains Pipeline 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 less than amounts specified reduce our operating and maintenance expenses in the period in which they are realized, to the extent they are within the loss allowance, and increase our operating and maintenance 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.

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 financial performance as a result of capital investemnts, acquisitions, divestitures and other strategic projects.

During the second quarter of 2016, management revised its internal and external use of non-GAAP measures to eliminate any adjustments to U.S. GAAP net earnings and earnings before interest, income taxes, and depreciation and amortization expense ("EBITDA") for items previously considered "special items" and loss attributable to our Predecessors. We believe our revised presentation of net earnings and EBITDA and descriptions of significant activities impacting U.S. GAAP net earnings are sufficient to convey our financial performance to the users of our financial statements.

Additionally, we revised our definition of Distributable Cash Flow to include the reconciliation of this non-GAAP measure to be from U.S. GAAP net cash from operating activities rather than net earnings. We believe this method of reconciliation is more appropriate based on our determination that Distributable Cash Flow provides a measure by which users of our financial statements can assess our ability to generate cash and thus additional liquidity.

Following these changes, our non-GAAP measures include the following:

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

• Liquidity non-GAAP measures:

◦ Distributable Cash Flow is derived from 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; and

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

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We present the performance and liquidity measures defined above because investors, analysts, lenders and rating agencies may use these measures to help analyze our results of operations and liquidity in conjunction with our U.S. GAAP results including, but not limited to, the following:

• 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.

In addition, these measures are used by management to assess internal performance. We believe these measures, when supplemental to information presented under U.S. GAAP, may provide meaningful information to the users of our financial statements. Each of the performance and liquidity measures should not be used in isolation from their comparable U.S. GAAP measure and thus should not be considered as alternatives to any U.S. GAAP measure. 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.

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 Tesoro (“Predecessor”) for the reasons described below:

Our financial information includes the historical results of our Predecessor and the results of TLLP for all periods presented. The financial statements of our Predecessor 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 Predecessor had been operated as an unaffiliated entity.

Revenues

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 combined consolidated financial statements contained in this Form 8-K. 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 existing 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 Rockies Natural Gas Business Acquisition, we began processing natural gas for certain producers under “keep-whole” processing agreements. See Note 3 to our combined consolidated financial statements contained in this Form 8-K for additional information on our “keep-whole” agreement with Tesoro.

RESULTS OF OPERATIONS

A discussion and analysis of the factors contributing to our results of operations presented below includes the combined 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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Summary

The following table and discussion is a summary of our results of operations for the years ended December 31, 2015, 2014 and 2013, including a reconciliation of EBITDA to net earnings and net cash from operating activities and Distributable Cash Flow and Pro Forma Distributable Cash Flow to net earnings (in millions, except per unit amounts). Our financial results may not be comparable as our Predecessors recorded revenues and general and administrative expenses, and financed operations differently than the Partnership as discussed in “Factors Affecting the Comparability of Our Financial Results.”

	Years Ended December 31,
	2015 (a)				2014 (a)				2013 (a)
Revenues
Gathering	$	339			$	135			$	90
Processing	278				23				—
Terminalling and Transportation (b)	495				442				223
Total Revenues	1,112				600				313
Costs and Expenses
Operating and maintenance expenses, net (c)	415				270				176
General and administrative expenses	102				74				32
Depreciation and amortization expenses	180				79				48
Net (gain) loss on asset disposals and impairments	1				(4		)		—
Total Costs and Expenses	698				419				256
Operating Income	414				181				57
Interest and financing costs, net	(150		)		(109		)		(39		)
Equity in earnings of unconsolidated affiliates	7				1				—
Earnings Before Income Taxes	271				73				18
Income tax expense	1				—				—
Net Earnings	270				73				18
Loss attributable to Predecessors	22				29				62
Net earnings attributable to noncontrolling interest	(20		)		(3		)		—
Net earnings attributable to Partners	272				99				80
General partner’s interest in net earnings, including incentive distribution rights	(73		)		(43		)		(12		)
Limited Partners’ Interest in Net Earnings	$	199			$	56			$	68
Net Earnings per Limited Partner Unit:
Common - basic	$	2.33			$	0.96			$	1.48
Common - diluted	$	2.33			$	0.96			$	1.47
Subordinated - basic and diluted	$	—			$	0.62			$	1.35
Weighted Average Limited Partner Units Outstanding:
Common units - basic	84.7				54.2				31.5
Common units - diluted	84.8				54.2				31.6
Subordinated units - basic and diluted	—				5.6				15.3

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	Years Ended December 31,
	2015 (a)				2014 (a)				2013 (a)
Reconciliation of Net Earnings to EBITDA:
Net earnings	$	270			$	73			$	18
Depreciation and amortization expenses	180				79				48
Interest and financing costs, net of capitalized interest	150				109				39
Income tax expense	1				—				—
EBITDA	$	601			$	261			$	105
Reconciliation of Net Cash from Operating Activities to Distributable Cash Flow and Pro Forma Distributable Cash Flow:
Net cash from operating activities	$	455			$	162			$	82
Changes in assets and liabilities	14				(7		)		(12		)
Predecessor impact	20				27				51
Maintenance capital expenditures (d)	(54		)		(44		)		(14		)
Reimbursement for maintenance capital expenditures (d)	9				7				5
Net earnings attributable to noncontrolling interest (e)	(18		)		(3		)		—
Other adjustments for noncontrolling interest (f)	(21		)		8				—
Adjustment for unconsolidated affiliates	(3		)		—				—
Gain on sale of Boise Terminal (g)	—				(5		)		—
Acquisition costs included in general and administrative expenses (h)	2				19				7
Billing of deficiency payments (i)	13				10				—
Inspection and maintenance costs associated with the Northwest Products System (j)	—				7				5
Other non-cash operating activities	6				25				2
Proceeds from sale of assets	(1		)		14				—
Distributable Cash Flow	422				220				126
Pro forma adjustment for acquisition of noncontrolling interest (k)	36				(1		)		—
Pro Forma Distributable Cash Flow	$	458			$	219			$	126

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(a) Includes the historical results related to the Partnership and Predecessors for the years ended December 31, 2015, 2014 and 2013.

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

(c) Operating and maintenance expenses include net imbalance settlement gains of $8 million, $17 million and $8 million for the years ended December 31, 2015, 2014 and 2013, 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 $34 million, $26 million and $4 million in the years ended December 31, 2015, 2014 and 2013, respectively.

(d) Maintenance capital expenditures include tank restoration costs and reimbursements, and expenditures required to ensure the safety, reliability, integrity and regulatory compliance of our assets. Maintenance capital expenditures included in the Distributable Cash Flow calculation are presented net of Predecessor amounts and the noncontrolling interest portion of maintenance capital expenditures.

(e) 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 combined consolidated financial statements contained in this Form 8-K, 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.

(f) 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.

(g) Includes a gain of $5 million for the year ended December 31, 2014, resulting from the sale of our Boise terminal.

(h) Reflects acquisition costs included in general and administrative expenses primarily related to the Rockies Natural Gas Business acquisition in 2015 and 2014 and the Northwest Products System acquisition in 2013.

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(i) Several of our contracts contain minimum volume commitments that allow us to charge the customer a deficiency payment if the customer’s actual throughput volumes are less than its minimum volume commitments for the applicable period. In certain contracts, if a customer makes a deficiency payment, that customer may be entitled to offset gathering fees or processing fees in one or more subsequent periods to the extent that such customer's throughput volumes in those periods exceed its minimum volume commitment. Depending on the specific terms of the contract, revenue under these agreements may be classified as deferred revenue and recognized once all contingencies or potential performance obligations associated with these related volumes have either been satisfied through the gathering or processing of future excess volumes of natural gas, or are expected to expire or lapse through the passage of time pursuant to terms of the applicable agreement. During December 2015 and 2014, we invoiced QEP Field Services, LLC customers for deficiency payments. We did not recognize $13 million and $10 million of revenue for 2015 and 2014, respectively; however, we are entitled to the cash receipt from such billing. The timing and amount of deficiency billings vary based on actual shortfall and terms under the applicable agreements.

(j) Includes costs for detailed inspection and maintenance program on the Northwest Products System, which improved the integrity of the Northwest Products Pipeline to meet the intent of the compliance order.

(k) 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.

Consolidated Results

Our net earnings for 2015 increased $197 million, or 270%, to $270 million from $73 million for 2014. The increase in net earnings was due to an increase in revenue of $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 segments increased $204 million and $255 million, respectively, benefiting from a full year of operations of the Rockies Natural Gas Business. Our terminalling and transportation segment’s revenues increased $53 million due to West Coast Logistics Assets that were acquired mid-year in 2014.

The increase in revenue resulting from the Rockies Natural Gas Business Acquisition and the West Coast Logistics Assets Acquisition was partially offset by a corresponding increase in expenses. Excluding the impact of acquisitions, operating expenses were relatively flat, general and administrative expenses increased due to higher allocated labor due to increased personnel headcount, and depreciation and amortization expenses increased due to projects being completed and placed into service including the Connolly Gathering System. 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.

Our net earnings for 2014 increased $55 million, or 306%, to $73 million from $18 million for 2013. The 2014 results included a net loss of $29 million related to the Predecessors and $3 million of earnings attributable to noncontrolling interest. The 2013 results included a net loss of $62 million related to the Predecessors. Our Predecessors did not record revenue for transactions with Tesoro, except for the RCA tariffs charged to Tesoro on the refined products pipeline included in the acquisition of the West Coast Logistics Assets. Net earnings attributable to the partners increased by $19 million from 2013 primarily related to an increase in revenue related to the 2013 acquisitions from Tesoro and the Northwest Products System Acquisition (collectively, the “2013 Acquisitions”), increases attributable to the Rockies Natural Gas Business Acquisition and higher throughput on our crude oil pipeline and trucking operations in our Gathering segment.

These increases in revenue during 2014 were offset by an increase in operating and maintenance expenses of $94 million primarily related to increased labor and operating costs related to the operations of the assets associated with the acquisitions in 2014 and 2013 and higher costs in our Gathering segment resulting primarily from higher throughput, an increase in general and administrative expenses primarily a result of higher costs, including acquisition and integration costs related to the 2014 acquisitions. Acquisition costs of $19 million for 2014 are included in unallocated general and administrative expenses. The increase in depreciation expense primarily related to the assets acquired in 2014 and for an entire year of activity in 2014 compared to partial activity in 2013 for the assets acquired in the 2013 Acquisitions. Net interest and financing costs increased $70 million primarily related to the additional debt issued in conjunction with the Rockies Natural Gas Business Acquisition and the acquisitions in 2014 and 2013 from Tesoro.

Gathering Segment

Our Gathering segment consists of crude oil, natural gas and produced water gathering systems in the Bakken Region and Rockies Region. 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 North Dakota 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 FERC through, which we provide natural gas and crude oil transportation services.

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The following table and discussion is an explanation of our results of operations of the Gathering segment (in millions, except volumes, revenue per barrel and revenue per MMBtu amounts).

	Years Ended December 31,
	2015				2014				2013
Revenues
Gas gathering revenues (a)	$	170			$	11			$	—
Crude oil gathering pipeline revenues	123				66				40
Crude oil gathering trucking revenues	46				58				50
Total Revenues	339				135				90
Costs and Expenses
Operating and maintenance expenses (b)	119				72				49
General and administrative expenses	10				5				3
Depreciation and amortization expenses	67				11				4
Loss on asset disposals	1				—				—
Total Costs and Expenses	197				88				56
Gathering Segment Operating Income	$	142			$	47			$	34
Volumes
Gas gathering volume (thousands of MMBtu/d)	1,077				1,046				—
Average gas gathering revenue per MMBtu	$	0.43			$	0.41			$	—
Crude oil gathering pipeline throughput (bpd)	187,836				123,355				85,572
Average crude oil gathering pipeline revenue per barrel	$	1.79			$	1.46			$	1.27
Crude oil gathering trucking (bpd)	38,461				49,339				44,363
Average crude oil gathering trucking revenue per barrel	$	3.25			$	3.23			$	3.10

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(a) Natural gas gathering revenues and volumes relate to the operations acquired in the Rockies Natural Gas Business Acquisition.

(b) Operating and maintenance expenses include net imbalance settlement gains of $2 million, $7 million and $2 million in the years ended December 31, 2015, 2014 and 2013, respectively.

2015 Compared to 2014

Volumes. Average gas gathering volumes were 1,077 thousand MMBtu/d in 2015, which contributed approximately 50% of total Gathering segment revenue. Average crude oil pipeline throughput volumes increased 64,481 bpd, or 52%, 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. This increase was almost entirely due to third-party volumes. Crude oil trucking throughput volumes decreased 10,878 bpd, or 22%, during 2015 as more volumes were gathered on our High Plains Pipeline.

Financial Results. Gathering revenues increased $204 million, or 151%, to $339 million in 2015 compared to $135 million in 2014 primarily due to the addition of natural gas gathering operations with the Rockies Natural Gas Assets as well as higher crude oil pipeline throughput on our High Plains Pipeline. These increases in gathering revenue were slightly offset by a decline in trucking revenues due to lower throughput volumes.

Operating and maintenance expenses increased $47 million, or 65%, to $119 million in 2015 compared to $72 million in 2014, primarily related to costs associated with 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 $56 million, or 509%, to $67 million in 2015 compared to $11 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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2014 Compared to 2013

Volumes. Average crude oil pipeline throughput volumes increased 37,783 bpd, or 44%, in 2014, primarily as a result of the expansion of our High Plains System and includes an increase of 25,539 bpd in third-party volumes. Crude oil trucking throughput volumes increased 4,976 bpd, or 11%, during 2014 compared to 2013, and include an increase of 5,993 bpd in volumes hauled by our proprietary fleet, partially offset by lower contract volume hauls. The increase in pipeline and trucking throughput reflects incremental volume on the High Plains Pipeline through the addition of new capacity associated with the High Plains Pipeline reversal during 2014. Average gas gathering volumes were 1,046 thousand MMBtu/d in 2014, which inclusive of other gas gathering revenues, contributed to approximately 8% of total Gathering segment revenue.

Financial Results. Gathering revenues increased $45 million, or 50%, to $135 million in 2014 compared to $90 million in 2013 primarily as a result of higher pipeline throughput and trucking volumes and one month of operations for the Rockies Natural Gas Business Acquisition.

Operating and maintenance expenses increased $23 million, or 47%, to $72 million in 2014 compared to $49 million in 2013. The increase is predominantly attributable to $17 million of expense for an accrual related to the remediation of the Crude Oil Pipeline Release. The increase also includes higher repair and maintenance costs associated with the increased throughput on the High Plains System as well as one month of activity for the operations acquired in the Rockies Natural Gas Business Acquisition included in the Gathering segment.

Depreciation and amortization expense increased $7 million, or 175%, to $11 million in 2014 compared to $4 million in 2013 primarily due to the growth of our crude oil gathering system and $4 million related to the natural gas gathering operations acquired in the Rockies Natural Gas Business Acquisition.

Processing Segment

The following table and discussion is an explanation of our results of operations of the Processing segment (in millions, except MMBtu/d, bpd and revenue per MMBtu and fee per barrel). The Processing segment, added as a result of the Rockies Natural Gas Business Acquisition on December 2, 2014, consists of gas processing complexes and a fractionation facility. Therefore, there was no activity to report for the processing segment for the year ended December 31, 2013.

	Years Ended December 31,
	2015				2014
Revenues
NGL processing revenues	$	96			$	7
Fee-based processing revenues	107				6
Other processing revenues	75				10
Total Revenues	278				23
Costs and Expenses
Operating and maintenance expenses	125				12
General and administrative expenses	4				1
Depreciation and amortization expenses	44				4
Total Costs and Expenses	173				17
Processing Segment Operating Income	$	105			$	6
Volumes
NGL processing volumes (bpd)	7,594				6,532
Average “keep-whole” fee per barrel of NGLs	$	34.46			$	35.51
Fee-based processing volumes (thousands of MMBtu/d)	743				693
Average fee-based processing revenue per MMBtu	$	0.39			$	0.30

2015 Compared to 2014

Volumes. Fee-based processing volumes increased 50 thousand MMBtu/d, or 7%, to 743 thousand MMBtu/d in 2015 and average NGL processing volumes increased 1,062 bpd, or 16%, to 7,594 bpd for the 2015 as a result of increased processing utilization of our complexes. The 2014 period only included the volumes beginning December 2, 2014 with the Rockies Natural Gas Business Acquisition.

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Financial Results. Total processing revenues were $278 million in 2015. This contributed approximately 25% to the Partnership’s total revenues. The increase in 2015 compared to 2014 is due to a full year of operations from the Rockies Natural Gas Assets in 2015 with a corresponding increase in expenses. Operating and maintenance expenses were $125 million in 2015, which contributed approximately 30% to total operating and maintenance expenses. Depreciation and amortization expense was $44 million in 2015, which represents approximately 24% of total depreciation and amortization expense for the year ended December 31, 2015. The 2014 period only reflect the expenses beginning December 2, 2014, with the Rockies Natural Gas Business Acquisition and are not comparable to the 2015 on an annualized basis due to seasonality and other fluctuations in processing volumes.

Terminalling and Transportation Segment

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

• 27 crude oil and refined products terminals and storage facilities in the western and midwestern U.S.; four marine terminals in California; a rail-car loading and unloading facilities in Washington and Alaska; 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.

• A bulk tank farm and terminal facility located at the Port of Anchorage in Anchorage, Alaska with 580,000 barrels of in-service storage capacity for refined products and which facility includes a truck rack and a rail-loading facility, and a terminal facility located at the Fairbanks International Airport in Fairbanks, Alaska, with 22,500 barrels of in-service capacity for refined products and which facility includes a truck rack.

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The following table and discussion are an explanation of our results or operations of the Terminalling and Transportation segment (in millions, except barrel and per barrel amounts).

	Years Ended December 31,
	2015				2014				2013
Revenues (a)
Terminalling revenues	$	377			$	333			$	184
Pipeline transportation revenues	118				109				39
Total Revenues	495				442				223
Costs and Expenses
Operating and maintenance expenses (b)	171				186				127
General and administrative expenses	34				29				12
Depreciation and amortization expenses	69				64				44
Gain on asset disposals and impairments	—				(4		)		—
Total Costs and Expenses	274				275				183
Terminalling and Transportation Segment Operating Income	$	221			$	167			$	40
Volumes (bpd)
Terminalling throughput (c)	934,697				917,280				738,665
Average terminalling revenue per barrel	$	1.11			$	1.00			$	0.69
Pipeline transportation throughput (c)	824,710				821,716				205,136
Average pipeline transportation revenue per barrel (c)	$	0.39			$	0.36			$	0.52

____________

(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 and maintenance expenses include net imbalance settlement gains of $4 million, $10 million and $6 million in the years ended December 31, 2015, 2014 and 2013, respectively.

(c) Volumes for all periods presented include both affiliate and third-party throughput including predecessor activity, as applicable, with the exception of transportation volumes on the pipeline assets acquired in the Los Angeles Logistics Assets Acquisition, which were not separately reported by Tesoro prior to the acquisition date. Therefore, related 2013 pipeline volume and revenue per barrel information has not been adjusted to include the activity prior to December 6, 2013.

2015 Compared to 2014

Volumes. Terminalling throughput volumes increased 17,417 bpd, or 2%, 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 volumes increased 2,994 bpd, 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 and maintenance expenses decreased $15 million, or 8%, to $171 million in 2015 compared to $186 million in 2014 primarily as a result of enhanced operational efficiency and asset utilization.

2014 Compared to 2013

Volumes. Terminalling throughput volumes increased 178,615 bpd, or 24%, in 2014 compared to 2013 primarily as a result of an entire year of activity for the 2013 acquisitions in 2014 compared to partial activity in 2013. Pipeline transportation throughput volumes increased 616,580 bpd, in 2014 compared to 2013 as a result of an entire year of activity in 2014 compared to partial activity in 2013 for the pipeline assets acquired in the Northwest Products System and Los Angeles Logistics Assets acquisitions. Pipeline volumes were not separately tracked by Tesoro prior to TLLP’s acquisition of the Los Angeles Logistics Assets on December 6, 2013 and were not retrospectively adjusted for 2013.

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Financial Results. Revenues increased $219 million, or 98%, to $442 million in 2014 compared to $223 million in 2013 primarily as a result of the new commercial agreements that went into effect in connection with the 2013 Acquisitions from Tesoro and the Northwest Products System Acquisition, which accounted for approximately $201 million of the revenue increase compared to 2013. The results reflect operations of the Northwest Products System, the Los Angeles Logistics Assets and the Los Angeles Terminal Assets for the entire year in 2014, compared to about seven months of operations of these assets in 2013. The increase in revenues in 2014 also includes $19 million from the West Coast Logistics Assets Acquisition subsequent to the acquisition date.

Operating and maintenance expenses increased $59 million, or 46%, to $186 million in 2014 compared to $127 million in 2013 primarily as a result of a full year of operations of the 2013 Acquisitions in 2014 compared to 2013. Operating and maintenance expenses reflect operations of the Northwest Products System, Los Angeles Terminal Assets and the Los Angeles Logistics Assets for the entire year in 2014, compared to approximately seven months of operations in 2013.

General and administrative expenses increased $17 million to $29 million in 2014 compared to $12 million in 2013 primarily due to increased expenses for certain allocated overhead costs associated with the 2013 Acquisitions for the entire year in 2014, compared to about seven months of operations of these assets in 2013.

Depreciation and amortization expense increased $20 million, or 45%, to $64 million in 2014 compared to $44 million in 2013. The increase is attributable to depreciation expense related to the 2013 Acquisitions. In 2013, depreciation expense was included for the Northwest Products System from the acquisition date on June 19, 2013, and the Los Angeles Terminal Assets from the acquisition date on June 1, 2013. The 2014 results include twelve months of depreciation for the assets acquired in 2013.

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 (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 year ended December 31, 2015, we issued an aggregate of 1,137,533 common units under our 2015 ATM Program, generating proceeds of approximately $59 million 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 $2 million related to the issuance of units under these programs for the year ended December 31, 2015.

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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. 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 incentive distribution rights during 2015. The table below summarizes the quarterly distributions related to our quarterly financial results:

Quarter Ended		Total Quarterly Distribution Per Unit				Total Quarterly Distribution Per Unit, Annualized				Total Cash Distribution (in millions)				Date of Distribution
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
December 31, 2014		0.6675				2.67				70				February 13, 2015
September 30, 2014		0.6425				2.57				66				November 13, 2014
June 30, 2014		0.6150				2.46				42				August 14, 2014
March 31, 2014		0.5900				2.36				39				May 15, 2014

We intend to pay a minimum quarterly distribution of at least $0.3375 per unit per quarter, which equates to approximately $32 million per quarter, or $129 million per year, based on the number of common and general partner units outstanding as of December 31, 2015. We do not have a legal obligation to pay this distribution.

Debt Overview

Our total debt, net of unamortized issuance costs of $2.8 billion is summarized as follows (in millions):

Debt, including current maturities:	December 31, 2015
Revolving Credit Facility	$	305
TLLP Term Loan	250
5.500% Senior Notes due 2019	500
5.875% Senior Notes due 2020	470
6.125% Senior Notes due 2021	550
6.250% Senior Notes due 2022	800
Capital lease obligations	8
Total Debt	2,883
Unamortized Issuance Costs (a)	(39		)
Debt, Net of Unamortized Issuance Costs	$	2,844

____________

(a) Includes an unamortized premium associated with our 5.875% Senior Notes due 2020 of $4 million as of December 31, 2015.

Revolving Credit Facility

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 2.92% at December 31, 2015. The Revolving Credit Facility is scheduled to mature on December 2, 2019.

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As of December 31, 2015, our Revolving Credit Facility was subject to the following:

Credit Facility		30 day Eurodollar (LIBOR) Rate		Eurodollar Margin		Base Rate		Base Rate Margin		Commitment Fee (unused portion)
Revolving Credit Facility (a)		0.43%		2.50%		3.50%		1.50%		0.50%

_______________

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

Revolving Credit Facility Amendment. 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 $1.0 billion secured 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 combined consolidated financial statements contained in this Form 8-K.

Covenants

The Revolving Credit Facility, Senior Notes due 2019, Senior Notes due 2020, Senior Notes due 2021 and Senior Notes due 2022 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.

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, 2015.

Unsecured Term Loan Facility

We entered into the Unsecured Term Loan Facility on November 12, 2015. The Unsecured Term Loan Facility allowed us to borrow up to an aggregate of $250 million, which we used to fund a portion of the LA Storage and Handling Assets from Tesoro. The Unsecured Term Loan Facility matures December 3, 2020, and may be repaid at any time, but amounts may not be re-borrowed. There were no payments on the borrowings under the Unsecured Term Loan Facility during the year ended December 31, 2015. The borrowings under our Unsecured Term Loan Facility incurred interest at a rate of 3.10% as of December 31, 2015, based on the following expense and fee schedule:

Credit Facility		30 day Eurodollar (LIBOR) Rate		Eurodollar Margin		Base Rate		Base Rate Margin
Unsecured Term Loan Facility ($250 million) (b)		0.35%		2.75%		3.50%		1.75%

_______________

(b) We can elect the interest rate to apply to the Unsecured Term Loan Facility between a base rate plus the base rate margin, or a Eurodollar rate, for the applicable term, plus the Eurodollar margin at the time of borrowing.

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The Unsecured Term Loan Facility contains affirmative and negative covenants, representations and warranties and events of default substantially similar to those set forth in the Revolving Credit Facility. There are no maintenance financial covenants associated with the Unsecured Term Loan Facility.

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.

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 and 6.25% Senior Notes due 2022 (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 as discussed in Note 8.

Senior Notes Issuance

On May 9, 2016, we completed a registered offering of $250 million aggregate principal amount of 6.125% Senior Notes due 2021 (the “2021 Senior 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 Senior Notes to repay amounts outstanding under our 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 Senior 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 Senior Notes have no sinking fund requirements. The 2021 Senior 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 Senior 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.

Cash Flow Summary

Components of our cash flows are set forth below (in millions):

	Years Ended December 31,
	2015 (a)				2014 (a)				2013 (a)
Cash Flows From (Used In):
Operating Activities	$	455			$	162			$	82
Investing Activities	(317		)		(2,673		)		(394		)
Financing Activities	(141		)		2,507				316
Increase (Decrease) in Cash and Cash Equivalents	$	(3	)		$	(4	)		$	4

______________

(a) Includes the historical results related to the Partnership and Predecessors for the years ended December 31, 2015, 2014 and 2013.

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2015 Compared to 2014

Net cash from operating activities increased $293 million to $455 million in 2015 from $162 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 $2.4 billion to $317 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 $141 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 $1.5 billion resulting from the public offering of 2.1 million common units representing limited partner interests (the “August 2014 Equity Offering”) and the registered public offering of 23 million common units in connection with the Rockies Natural Gas Business Acquisition (the “October 2014 Equity Offering”) and $1.3 billion of aggregate principal senior notes, completed in a private offering (the “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.

2014 Compared to 2013

Net cash from operating activities increased $80 million to $162 million in 2014 from $82 million in 2013. The increase in net cash from operating activities was attributable to higher revenues and operating income as a result of our Acquisitions from Tesoro, primarily from the increase in revenues associated with the commercial agreements that went into effect on the acquisition dates, and an increase in revenues and operating income as a result of the December 2014 Rockies Natural Gas Business Acquisition and the June 2013 Northwest Products System acquisition. The revenues and operating income for the Los Angeles Terminal Assets Acquisition, the Los Angeles Logistics Assets Acquisition and the Northwest Products System acquisition reflect the entire year in 2014, compared to about seven months of operations of these assets in 2013. This increase was partially offset by an increase in cash paid for interest costs during 2014 compared to 2013 related to the issuance of the 2019 Senior Notes and 2022 Senior Notes, as well as $16 million of fees for an alternative financing arrangement related to the Rockies Natural Gas Business Acquisition.

Net cash used in investing activities increased $2.3 billion to $2.7 billion in 2014 compared to $394 million in 2013. We paid $2.5 billion upon closing the Rockies Natural Gas Business Acquisition in December 2014 compared to $315 million for the Northwest Products System acquisition in 2013. Capital expenditures in 2014 increased by $125 million compared to 2013 primarily as a result of spending on the High Plains Pipeline reversal project and the construction of the Bakken area storage hub. See “Capital Expenditures” below for a discussion of the various maintenance and growth projects in 2014, including those reimbursed by our customers. Cash provided by investing activities in 2014 included proceeds of $10 million from the sale of our legacy Boise terminal.

Net cash from financing activities increased $2.2 billion to $2.5 billion in 2014 from $316 million in 2013. The net cash provided by financing activities in 2014 included the net proceeds of $1.5 billion resulting from the August 2014 Equity Offering and October 2014 Equity Offering and $1.3 billion from the Senior Notes Offering. The cash payments for the acquisition of the West Coast Logistics Assets from Tesoro of $243 million were treated as a cash distribution to Tesoro for accounting purposes. We borrowed amounts under our Revolving Credit Facility to fund cash portions of the West Coast Logistics Assets Acquisition from Tesoro and the Rockies Natural Gas Business Acquisition. We paid higher quarterly cash distributions totaling $183 million in 2014 compared to quarterly cash distributions of $102 million paid in 2013. In addition, financing costs increased $16 million in 2014 compared to 2013, primarily related to the amendment to the Revolving Credit Facility completed on December 2014 and the Senior Notes Offering.

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 $25 million, $31 million and $43 million included in cash from financing activities in 2015, 2014 and 2013, respectively, funded the cash portion of the net loss for the Predecessors.

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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.

2015 Capital Expenditures. During 2015, we spent $224 million, net of $19 million in reimbursements from entities including Tesoro, on growth capital projects and $44 million, net of $9 million in reimbursements from entities including Tesoro, on maintenance capital projects. The following major growth capital projects were completed during 2015 (in millions):

	Total Project Expected Capital Expenditures				Actual 2015 Capital Expenditures
Connolly Gathering System (a)	$	148			$	100
Anacortes Light Products Truck Rack (b)	23				12
Southern California Distribution System (c)	22				12

_______________

(a) The Connolly Gathering System gathers crude oil from various points in Dunn County, North Dakota for delivery at the existing Connolly Station and has a capacity of approximately 60,000 bpd. The project was substantially completed by December 2015.

(b) A new light products truck rack at the site of the existing Anacortes terminal acquired as part of the West Coast Logistics Assets, which added approximately 8,000 barrels per day of additional gasoline and diesel throughput capacity. The project was operational in November 2015. The total capitalized project was $30 million, of which $23 million was cash spending. Additionally, we recognized an equity contribution of $7 million from Tesoro related to Tesoro’s full construction cost of $30 million.

(c) Projects to expand and optimize the southern California distribution system increase throughput and expand ancillary service capabilities.

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2016 Capital Expenditures. TLLP's expected 2016 capital expenditures are currently being reevaluated in light of the current market environment. While still under evaluation, we anticipate we will materially reduce our 2016 capital expenditures of $493 million, as presented in December 2015, relative to our capital investment plans. This reduction is primarily driven by deferrals of discretionary projects and delays in several growth projects in both the Rockies and Bakken regions attributed to low commodity prices and our current view of spending related to the Los Angeles Refinery Interconnect Pipeline System.

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. The following highlights several of our major growth capital projects in process or under development (in millions):

		Total Project Expected Capital Expenditures		Actual 2015 Capital Expenditures
In Process:
Uinta Compression (a)		$ 50 - 60		$	—
High Plains Pipeline Expansion (b)		40 - 50		7
Charging Eagle Gathering System (c)		40 - 50		—
Bakken Area Storage Hub (d)		25 - 30		21
Under Development:
Los Angeles Refinery Interconnect Pipeline System (e)		$ 175 - 200		$	—

_______________

(a) Projects to increase compression for our Uinta natural gas gathering systems and expand our gathering system in the Uinta basin.

(b) Projects to expand crude oil gathering throughput capacity on the High Plains Pipeline in McKenzie County, North Dakota.

(c) The construction of the Charging Eagle Gathering System, a crude oil and produced water gathering and treating system in eastern Dunn County, North Dakota. This project has been deferred due to current commodity market conditions.

(d) The construction of the second phase of the Bakken Area Storage Hub provides storage for the Bakken region with tanks located in two strategic areas of the basin. It currently has approximately 780,000 barrels of storage capacity and is expected to grow to over 1 million barrels of capacity.

(e) The pipeline interconnect project at the Los Angeles refinery is designed to improve the flexibility of gasoline and diesel yields and reduce carbon dioxide emissions. The proposed project is subject to final Board approval, project scoping, engineering and regulatory approval.

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Contractual Obligations

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 10 and 11 to our combined consolidated financial statements contained in this Form 8-K). We also have minimum contractual spending requirements for certain capital projects. A summary of our contractual obligations as of December 31, 2015, is as follows (in millions):

	2016				2017				2018				2019				2020				Thereafter				Total
Long-term debt obligations (a)	$	155			$	155			$	155			$	955			$	832			$	1,467			$	3,719
Capital lease obligations (b)	1				1				1				1				1				7				12
Operating lease obligations (c)	12				10				9				8				7				63				109
Other purchase obligations (d)	85				84				84				84				84				61				482
Capital expenditure obligations (e)	53				—				—				—				—				—				53
Total Contractual Obligations	$	306			$	250			$	249			$	1,048			$	924			$	1,598			$	4,375

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(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 NGL transportation costs, fractionation fees, and fixed charges under the Amended Omnibus Agreement, and the Secondment 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, 2015 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 11 and Note 1, respectively, to our combined consolidated financial statements contained in this Form 8-K.

Off Balance Sheet Arrangements

We have not entered into any transactions, agreements or other contractual arrangements, other than our leasing arrangements described in Note 11 to our combined consolidated financial statements contained in this Form 8-K 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.

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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 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 our initial public offering in April 2011 (“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 and discussion of certain environmental obligations that were retained by Chevron Pipe Line Company and Northwest Terminalling Company in conjunction with the acquisition of the Northwest Products System.

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 $33 million and $32 million at December 31, 2015 and 2014, respectively.

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 $24 million during the year ended December 31, 2015, 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 December 31, 2015, and $18 million at December 31, 2014. The estimated remediation costs of $66 million exceeded our policy loss limit by $41 million as of December 31, 2015. We received insurance proceeds of $18 million and $7 million in reimbursement of costs incurred during the years ended December 31, 2015 and 2014, respectively.

See Note 11 to our combined consolidated financial statements contained in this Form 8-K for additional information regarding our environmental liabilities and legal proceedings.

Other Environmental Spending

We completed a detailed inspection and maintenance program in 2015, which included spending of $24 million inception to date to perform inspections and repairs that improved the integrity of the Northwest Products System. This included the costs to comply with the Corrective Action Order (“CAO”) and also costs expected for inspections and repairs on other sections of the pipeline. The purchase price of the Northwest Products system was reduced by $45 million to compensate the Partnership for assuming responsibilities under the CAO and to perform additional inspection and maintenance as the Partnership deemed necessary.

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 combined consolidated financial statements contained in this Form 8-K for additional information regarding our Amended Omnibus Agreement and the Carson Assets Indemnity Agreement.

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ACCOUNTING STANDARDS

Critical Accounting Policies and Estimates

Our significant accounting policies and recent accounting developments are described in Note 1 to our combined consolidated financial statements contained in this Form 8-K. 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, intangible assets and equity method investments) 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 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 $130 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, 2015 goodwill impairment assessment. Furthermore, the fair value of each of the five reporting units tested in step one of the goodwill impairment test were significantly in excess of the carrying value, and as such, we were not required to perform step two.

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Environmental Liabilities. At December 31, 2015, our total environmental liabilities included in other current liabilities and other noncurrent liabilities were $33 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, 2015, 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 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 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 combined consolidated financial statements contained in this Form 8-K.

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