Andeavor Logistics 8K Entry into a Material Definitive Agreement | ANDX 7 Aug 18

Exhibit 10.1

Execution Version

SECOND AMENDED AND RESTATED SCHEDULES

TO FOURTH AMENDED AND RESTATED OMNIBUS AGREEMENT

A Fourth Amended and Restated Omnibus Agreement was executed as of October 30, 2017 (the “Fourth Amended and Restated Omnibus Agreement”), among Andeavor, on behalf of itself and the other Andeavor Entities, Tesoro Refining & Marketing Company LLC, Tesoro Companies, Inc., Tesoro Alaska Company LLC, Andeavor Logistics LP and Tesoro Logistics GP, LLC. Capitalized terms not otherwise defined in this document shall have the terms set forth in the Fourth Amended and Restated Omnibus Agreement.

The Parties agree that the Schedules are hereby amended and restated in their entirety as of the date hereof to be as attached hereto. Pursuant to Section 9.12 of the Fourth Amended and Restated Omnibus Agreement, such amended and restated Schedules shall replace the prior First Amended and Restated Schedules as of the date hereof and shall be incorporated by reference into the Fourth Amended and Restated Omnibus Agreement for all purposes.

[Signature Page Follows]

Executed as of August 6, 2018.


ANDEAVOR

By:		/s/ Gregory J. Goff
		Gregory J. Goff
		President and Chief Executive Officer

TESORO REFINING & MARKETING COMPANY LLC

By:		/s/ Gregory J. Goff
		Gregory J. Goff
		President and Chief Executive Officer

TESORO COMPANIES, INC.

By:		/s/ Gregory J. Goff
		Gregory J. Goff
		President and Chief Executive Officer

TESORO ALASKA COMPANY LLC

By:		/s/ Gregory J. Goff
		Gregory J. Goff
		President and Chief Executive Officer

Signature Page

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


ANDEAVOR LOGISTICS LP

By:		Tesoro Logistics GP, LLC,
		its general partner

By:		/s/ Steven M. Sterin
		Steven M. Sterin
		President and Chief Financial Officer

TESORO LOGISTICS GP, LLC

By:		/s/ Steven M. Sterin
		Steven M. Sterin
		President and Chief Financial Officer

Signature Page

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule I

Pending Environmental Litigation

For Initial Contribution Agreement listed on Schedule VII:

None.

For Amorco Contribution Agreement listed on Schedule VII:

None.

For Long Beach Contribution Agreement listed on Schedule VII:

The soil and groundwater on the southern central portion of the site near the24-inch crude oil line have been impacted with hydrocarbons from a release from the line first observed in September 2011. The California Regional Water Quality Control Board issued an Investigative Order dated September 30, 2011 and to date all requirements of the order have been met. Additional investigative or remedial activities may be required.

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

The environmental indemnification provisions of the Carson Assets Indemnity Agreement dated as of December 6, 2013 (“Carson Assets Indemnity Agreement”), among the Partnership, the General Partner, Tesoro Logistics Operations LLC (the “Operating Company”) and TRMC, supersede in their entirety the environmental indemnification provisions of Article III of the Fourth Amended and Restated Omnibus Agreement, except as otherwise expressly provided in the Carson Assets Indemnity Agreement.

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

The environmental indemnification provisions of the Carson Assets Indemnity Agreement supersede in their entirety the environmental indemnification provisions of Article III of the Fourth Amended and Restated Omnibus Agreement, except as otherwise expressly provided in the Carson Assets Indemnity Agreement.

For West Coast Assets Contribution Agreement listed on Schedule VII:

None.

Schedule I- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

None.

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

KENAI TANKAGE:Andeavor, Tesoro Alaska, TRMC, the Partnership and the General Partner are subject to a pending consent decree with the United States Environmental Protection Agency and the Department of Justice pursuant to which injunctive relief will be ordered with respect a number of refineries (the “2016 Environmental Consent Decree”).

ANCHORAGE AND FAIRBANKS TERMINALS:Andeavor, Tesoro Alaska, TRMC, the Partnership and the General Partner are subject to the pending 2016 Environmental Consent Decree pursuant to which injunctive relief will be ordered with respect a number of refineries.

The indemnification obligations of the Andeavor Entities under Section 3.1(a) of the Fourth Amended and Restated Omnibus Agreement with regard to the 2016 Environmental Consent Decree are limited as provided in Schedule IX.

For Martinez Assets Contribution Agreement listed on Schedule VII:

Andeavor, Tesoro Alaska, TRMC, the Partnership and the General Partner are subject to the 2016 Environmental Consent Decree.

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

The environmental indemnification provisions in Article VI of the Sponsor Equity Restructuring Agreement dated August 13, 2017 (“SERA”) between Andeavor, Andeavor Logistics LP and Tesoro Logistics GP, LLC supersede in their entirety the environmental indemnification provisions of Article III of the Fourth Amended and Restated Omnibus Agreement, other than Section 3.5(b), and shall be the exclusive provisions for all indemnification obligations relating to the subject matter of the indemnities so provided in Article VI of the SERA.

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

In July 2016, the US EPA and the U.S. Department of Justice announced a $425 million settlement with TRMC, including the TRMC Anacortes Refinery, in relation to violations of the Clean Air Act. The settlement (the Consent Decree) with the U.S. Department of Justice requires that the storage tanks be added to the Refinery’s LDAR program and be monitored regularly for leaks. Some valve locations are difficult to monitor and may require relocation nearer to grade. These locations have been identified and will be addressed when the tanks are taken out of service during inspections. Per the Consent Decree, the Refinery must install closed-purge, closed-loop, or closed-vent samplers at all storage tanks by 2021. According to facility representatives, there are 42 tanks left to retrofit.

Schedule I- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

The recent Consent Decree with the U.S. Department of Justice has required that the Refinery perform a BWON (Benzene Waste Operations National Emission Standards for Hazardous Air Pollutants) Audit to recalculate the Total Annual Benzene amount and the total benzene emitted under the 2 Mg per year exemption. During this process, the Refinery determined that it exceeded the 2 Mg exemption and reported the exceedance to NWCAA in the 2016 Annual Compliance Certification air operating permit.

For 2018 Assets Contribution Agreement listed on Schedule VII:

With respect to the Mandan Rail Rack and Trackage and the Salt Lake Rail Rack and Trackage (each as defined in the 2018 Assets Contribution Agreement), an August 2013 Fuels Consent Decree contains provisions that apply to tanks storing Conventional Gasoline. Capital Improvements and Audits have been performed under the Consent Decree, but the tanks are still subject to a mandated System-Wide Compliance Plan for sampling tank contents.

With respect to the LARW Refinery Unit, the LARC Refinery Unit, and the LA Refinery Interconnecting Pipeline (each as defined in the 2018 Assets Contribution Agreement), litigation by environmental advocacy group(s),CBE v. SCAQMD, challenging the LARIC Environmental Impact Review for combining the LARW Refinery Unit and the LARC Refinery Unit. Contests anything within scope of that EIR, including LA Refinery Interconnecting Pipeline connections.

For LARC Refinery Unit operations and assets only, the 2001 EPA Consent Decree entitledU.S. and the State of Indiana, State of Ohio, and the Northwest Air Pollution Authority, Washington v. BP Exploration & Oil Co.

LARC Tankage (as defined in the 2018 Assets Contribution Agreement) was issued Cleanup and Abatement Order (CAO)No. 90-121, dated 22 August 1990.

Certain of the Assets (as defined in the 2018 Assets Contribution Agreement) are subject to a 2016 Environmental Consent Decree with the United States Environmental Protection Agency and the Department of Justice.

Schedule I- Page 3 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule II

Environmental Matters

For Initial Contribution Agreement set forth on Schedule VII:

1. Anchorage #1 Terminal soil and groundwater have been impacted by gasoline and diesel releases from previously buried pipelines. The site is considered characterized and is currently undergoing removal of product from the water table, groundwater treatment, and long-term monitoring.

2. Anchorage #2 Terminal soil and groundwater have been impacted by gasoline releases occurring prior to Andeavor’s purchase of the facility. The site is considered characterized and is currently undergoing groundwater monitoring and treatment.Off-site groundwater investigations are scheduled for 2012.

3. Stockton Terminal soil and groundwater have been impacted by gasoline and diesel releases from pipelines and/or product storage tanks. The site is considered substantially characterized and is undergoing groundwater treatment and groundwater monitoring.Off-site groundwater impacts are commingled with neighboring petroleum storage terminals.

4. Burley Terminal groundwater was impacted by gasoline releases occurring prior to Andeavor’s purchase of the facility. Groundwater impacts were commingled with neighboring petroleum storage terminals. Hydrocarbon concentrations in groundwater samples do not exceed previously established target levels for groundwater and surface water protection. Regulatory closure is pending.

5. Wilmington Sales Terminal soil and groundwater have been impacted by gasoline releases occurring prior to Andeavor’s purchase of the facility. Groundwater investigation and monitoring ison-going. Andeavor is indemnified by the previous owner for Investigation and remediation obligations.

6. Salt Lake City Terminal soil and groundwater have been impacted by gasoline and diesel releases from pipelines and/or product storage tanks occurring prior to Andeavor’s purchase of the facility. The site is considered characterized and is currently undergoing removal of product from the water table and long-term monitoring. There are no known soil or groundwater impacts at the Northwest Crude Oil tank farm.

7. The Stockton Terminal emits volatile organic compounds (VOCs) below “major source” emission criteria. In 2010, the San Joaquin Air Quality Management District announced it is reducing its major source threshold. When the Stockton Terminal expands its operations or increases throughput, the potential to emit VOC will increase and the Stockton terminal will become subject to regulation as a major source. This will require a Title V Air Operating Permit. In addition, the Stockton facility will be required to install an automated continuous emission monitor at a cost of approximately $75,000.

Schedule II- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Amorco Contribution Agreement set forth on Schedule VII:

1. The soil and groundwater on the site of the Tankage, as defined in the Amorco Contribution Agreement, have been impacted by methyl tertiary butyl ether releases from previously buried pipelines. The site is considered characterized and is currently undergoing removal of methyl tertiary butyl ether from the water table, groundwater treatment, and long-term monitoring.

2. Any environmental violation or contamination due to SHPL, as defined in the Amorco Contribution Agreement, being underground prior to the Closing Date.

For Long Beach Contribution Agreement listed on Schedule VII:

1. Any environmental violation or contamination, as defined in the Long Beach Contribution Agreement, prior to the Closing Date.

2. Any anomalies in the Pipeline System that require repair as discovered by the first internal line inspection of any portion of the Pipeline System for which TRMC is notified in writing prior to the First Deadline Date.

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

Schedule II- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For West Coast Assets Contribution Agreement listed on Schedule VII:

1.Nikiski Terminal. Subsurface soil and groundwater has not been assessed at this facility. There have been no historic releases that have prompted a soil and groundwater investigations. The area within the tank containment berms was lined withlow-permeability soils in the early 1990s. The loading rack, fuel filters and piping manifolds are above concrete secondary containment.

2.Anacortes Light Ends Rail Facility and planned diesel truck rack areas. Subsurface soil and groundwater has not been assessed at this area of the Anacortes refinery. There have been no historic releases that have prompted a soil and groundwater investigation.

3.Anacortes Storage Facility. Historic tank overtopping events and tank bottom corrosion releases have impacted soil and groundwater in the shore tank area of the Anacortes refinery. Groundwater near the shore tanks is monitored for natural attenuation. Groundwater between the tanks and the nearby shoreline has not been characterized, however the hydrocarbon concentrations in this area is not expected to be a threat to human health or the environment.

4.Martinez Refinery LPG Loading Area. Past waste disposal and hydrocarbon releases have impacted areas surrounding the Martinez Refinery LPG loading rack, pad and tanks. Areas north and northeast of the rack were used for past waste disposal. There are documented intra-refinery pipeline releases in the north and western boundaries of the LPG rack concrete pad. The refinery plans to excavate and cap the nearby waste disposal area in 2017. The pipeline releases are being remediated as part of the overall Martinez refinery cleanup. Soil and groundwater directly beneath the loading rack, propane tanks and truck pad have not been sampled.

5.Tesoro Alaska Pipeline.

•

The pump station for the Tesoro Alaska Pipeline is adjacent to the Kenai Refinery Lower Tank Farm. Multiple historic tank and buried pipeline releases have impacted soil and groundwater in the area; however there are no documented releases from the pipeline pump station. The soil and groundwater surrounding the pump station is considered characterized and undergoing groundwater monitoring and treatment.

•

A pipeline release in 2001 resulted in soil, groundwater and surface water impacts in an undeveloped area of the Kenai Peninsula. The quantity of the release is not known. Soil surrounding the release was excavated and stockpiled at the Kenai Refinery while groundwater and surface water were remediatedon-site. The Alaska Department of Environmental Conservation issued a No Further Action letter for this cleanup effort in 2008. There are no other known release sites on the pipeline between the Kenai Refinery and Anchorage.

Schedule II- Page 3 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

•

Historic spills and releases have impacted the Anchorage #1 terminal, including past releases from the Tesoro Alaska Pipeline receiving station. Groundwater remediation monitoring is ongoing across the Anchorage #1 terminal. In addition, a soil vapor venting system is being installed to address a flame suppressant compound detected in soils near the receiving station control room.

For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

None

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

KENAI TANKAGE:

Area of significant groundwater and soil impacts: (1) lower tank farm groundwater impact source area including 1988 jet fuel release and unknown light products release in area of Tank 63, (2) process unit historic releases from oily water sewer system including releases from failed grout in subsurface sewer hubs, (3) groundwater issues generally 35 to 40 feet below ground surface and groundwater impacts in three water-bearing zones below refinery andoff-site and (4) possible contributor to refinery-wide groundwater impacts.

ANCHORAGE AND FAIRBANKS TERMINALS:

Pursuant to the Contribution, Conveyance and Assumption Agreement effective as of July 1, 2016 (the “Alaska Assets Contribution Agreement”), among Tesoro Logistics LP, a Delaware limited partnership (the “Partnership”), Tesoro Logistics GP, LLC, a Delaware limited liability company and the general partner of the Partnership (the “General Partner”), Tesoro Logistics Operations LLC, a Delaware limited liability company (the “Operating Company”), Tesoro Alaska Company LLC, a Delaware limited liability company (“TAC”) and Tesoro Corporation, a Delaware corporation (“Tesoro”), TAC contributed 100% of the limited liability company interests (the “TAT Interests”) in Tesoro Alaska Terminals LLC, a Delaware limited liability company (“TAT”), to the General Partner, the General Partner contributed 100% of the TAT Interests to the Partnership, and the Partnership contributed 100% of the TAT Interests to the Operating Company, all on the terms and conditions set forth in that contribution agreement.

Prior to the date of the Alaska Assets Contribution Agreement, TAT acquired certain assets defined as the “Anchorage and Fairbanks Terminals” in the Alaska Assets Contribution Agreement from Flint Hills Resources Alaska, LLC pursuant to an Asset Purchase Agreement, dated November 20, 2015 (the “Flint Hills APA”), by and between Flint Hills Resources Alaska, LLC and TAC. As described in the Flint Hills APA, the following liabilities existed at the Anchorage and Fairbanks Terminals prior to the closing of the transactions contemplated under the Flint Hills APA:

Schedule II- Page 4 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Anchorage Terminal:

Deviations reported under Anchorage Air Permit No. AQ0235TVP03, Issue Date: April 2, 2014, Effective Date: May 2, 2014

•

Flint Hills Resources Alaska, LLC did not submit a report as required under Condition 68 based upon defects listed in Condition 6.3 discovered during the out of service inspection conducted onT-4216 during July 2014. The deviation report covering this incident is set out in the Flint Hills Resources Alaska, LLC deviation report dated January 29, 2015.

•

Flint Hills Resources Alaska, LLC did not report all emissions or operations that exceed or deviate from the requirements of its permit within 30 days of the end of the month in which the excess emission or deviation occurred. The deviation report covering this incident is set out in the Flint Hills Resources Alaska, LLC deviation report dated January 29, 2015.

•

Flint Hills Resources Alaska, LLC did not perform preventative maintenance in accordance with 40 CFR Subpart ZZZZ within 365 days of effective date on EU IDs 7, 8, and 9. The maintenance was performed 2 days after that date. The deviation report covering this incident is set out in the Flint Hills Resources Alaska, LLC deviation report dated July 30, 2014.

•

Flint Hills Resources Alaska, LLC did not report all emissions or operations that exceed or deviate from the requirements of this permit within 30 days of the end of the month in which the excess emissions or deviation occurred. The deviation report covering this incident is set out in the Flint Hills Resources Alaska, LLC deviation report dated January 29, 2015.

•

On April 10, 2014. ADEC issued Flint Hills Resources Alaska, LLC a letter of Acceptance of the Anchorage Facility Compliance Certificate, and identified 4 deviations from the air permit.

In a letter dated July 22, 2015, the ADEC indicated that the Anchorage Terminal Oil Discharge Prevention and Contingency Plan needed the additional information specified in the July 22, 2015 letter to be submitted in order for the plan renewal to be approved. On September 2, 2015, the facility submitted the requested information and is awaiting ADEC approval.

On May 15, 2015 Flint Hills Resources Alaska, LLC received a notice of failure to pay Air Quality fees relating to Air Permit No. AQ0235TVP03. Those fees were paid on June 2, 2015.

In a letter dated October 1, 2015, ADEC approved the facility’s request for a waiver of secondary containment, subject to the terms of the letter, until March 31, 2016.

Schedule II- Page 5 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

On July 24, 2014 ADEC issued a letter to Flint Hills Resources Alaska, LLC advising that Flint Hills Resources Alaska, LLC is a responsible party under Alaska law for the July 22, 2014 Anchorage Facility Jet Fuel release.

On April 21, 2014, ADEC issued a letter to Flint Hills Resources Alaska, LLC advising it that Flint Hills Resources Alaska, LLC is a responsible party under Alaska law for the April 20, 2014 gasoline release.

Fairbanks Terminal:

(i)

In a letter dated May 29, 2015, ADEC detailed items that needed correction related to ADEC’s May 19, 2015 inspection of the terminal and its Oil Discharge Prevention and Contingency Plan. The facility has submitted a response to ADEC and is working with the agency to correct the identified items.

(ii)

On April 24, 2014 ADEC advised Flint Hills Resources Alaska, LLC that the Primary Response Action Contractor is no longer an ADEC approved and registered contractor. Therefore, Flint Hills Resources Alaska, LLC’s Fairbanks Facility Oil Discharge Prevention and Contingency Plan was out of compliance and needed amendment.

(iii)

Two underground storage tanks are located at the Fairbank Terminal, both of which are used to store heating oil. One underground storage tank was removed from the Purchased Site prior to Flint Hills Resources Alaska, LLC’s leasehold.

(iv)

Asbestos materials has been identified and are known to be located at the Anchorage Facility in the following locations:


*Material Type*	*Location(s)*	*EPA Category*

Gray Caulk (10% Chrysotile)	Fire Pump Room, Warehouse	Category II

Sheetrock (4% Chrysotile)	Boiler Room, Warehouse	Category II

Brown Insulation (5% Chrysotile)	Heat Exchanger Building	Category I

Window Caulk (3% Chrysotile)	Warehouse	Category II

Gray Mastic (10% Chrysotile)	Concrete Pad Near Tank 4136	Category II

Black Mastic (6% Chrysotile)	Concrete Pad Near Tank 4136	Category II

Black Mastic (17% Chrysotile)	Exchanger on West Side of Asphalt Tank Farm	Category II

Black Mastic (6% Chrysotile)	Piping located near railroad tracks on Ocean Dock Road.	Category II

Black Mastic (20% Chrysotile)	Piping on side of Tank 4263, East Tank Farm	Category II

White Insulation (60% Chrysotile)	Piping on side of Tank 4263, East Tank Farm	Category I

Mastic/Insulation (20% Chrysotile)	Top skirt of Tank 4263, East Tank Farm	Category I

Mastic (15% Chrysotile)	Sections of buried pipelines	Category II

Schedule II- Page 6 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

In the Flint Hills APA, Flint Hills Resources Alaska, LLC noted that it had no knowledge of other asbestos-containing material currently located at the sites purchased by TAT. However, Flint Hills Resources Alaska, LLC noted that asbestos material has been removed in the past during renovation and/or demolition work at the purchased sites.

Flint Hills Resources Alaska, LLC stated in the Flint Hills APA that it has no knowledge of polychlorinated biphenyls (“PCB”) material or equipment containing PCBs existing at the purchased sites. Flint Hills Resources Alaska, LLC, however, noted that it understands that PCBs may have been present under prior lessees operations of the sites but has no direct knowledge of this.

Flint Hills Resources Alaska, LLC stated in the Flint Hills APA that it understands “disposal areas” to include areas where Hazardous Materials have been Released. See Section 3.11(h) of Seller Disclosure Schedule under the Flint Hills APA for Flint Hills Resources Alaska, LLC’s knowledge regarding disposal areas on the Purchased Sites. In addition, a significant amount of fill material was used to augment the elevation and stability of the soils beneath the Anchorage facility. This fill included debris and materials such as such as wood, metal, and concrete. Flint Hills Resources Alaska, LLC stated in the Flint Hills APA that it has no knowledge that the fill material contained Hazardous Materials when it was placed on the site.

Flint Hills Resources Alaska, LLC stated in the Flint Hills APA that:

In a letter dated July 22, 2015, ADEC indicated that the Anchorage Terminal Oil Discharge Prevention and Contingency Plan needed the additional information specified in the July 22 letter to be submitted in order for the plan renewal to be approved. On September 2, 2015, the facility submitted the requested information and is awaiting ADEC approval.

Flint Hills Resources Alaska, LLC assumed all environmental liabilities known at the time the Purchased Facilities were acquired from Williams in 2004.

Schedule II- Page 7 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Martinez Assets Contribution Agreement listed on Schedule VII:

MARTINEZ TANKAGE:

The following pending refinery notices of violation:

Notice issued April 16, 2013 by the Bay Area Air Quality Management District (“BAAQMD”) related to liquid discovered on internal floating roof of Tank 870;

Notice issued February 11, 2014 by BAAQMD related to a leaking PV valve on Tract 3 VRS Tank 613; and

Notice issued August 12, 2014 by BAAQMD related to a¹⁄₂ inch gap at well sliding cover on Tank 692.

Existing soil and groundwater contamination has been identified and is being managed under existing programs and agreements by TRMC and third parties, within three (3) solid waste management units located on Tract 3 of the “Licensed Premises” (as defined in the November 21, 2016 License Agreement between TRMC and the Operating Company)Anacortes, on which the crude oil, feedstock and refined product storage tankage are situated, with such waste management units being identified as areas within red or green boundary lines on the WMU HAZARDMAP-Orientation Unit Or System Overall General Sheets, as reflected on the Golden Eagle Refinery Plat, Drawing Number020-DA-518-001, as copy of which is shown below.

LOGO

Schedule II- Page 8 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

None. The environmental indemnification provisions in Article VI of the Sponsor Equity Restructuring Agreement dated August 13, 2017 (“SERA”) between Andeavor, Andeavor Logistics LP and Tesoro Logistics GP, LLC supersede in their entirety the environmental indemnification provisions of Article III of the Fourth Amended and Restated Omnibus Agreement, other than Section 3.5(b), and shall be the exclusive provisions for all indemnification obligations relating to the subject matter of the indemnities so provided in Article VI of the SERA.

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

The transfer piping on the wharf has not been reviewed for risk of surge. In the event of misalignment during cargo operations or accidental valve closure on vessel or shore there is a potential to overpressure the transfer piping. A surge study will be conducted and any required modifications will be undertaken.

There is a seep of oil through the north secondary containment dike for Tanks 6 and 7 and into the adjacent storm water swale. Absorbent booms are placed at intervals in the swale to contain the oil. Any oil that makes its way to the wastewater treatment facility can be managed at the flume. Additional information about the seep, as well as investigation efforts to determine the source, was provided in a memo from Pacific Groundwater Group. Investigation efforts have not yet identified the source of the seep. TRMC personnel have reported the seep to the Washington State Department of Ecology Industrial Section.

The tank containment dikes are coated with asphalt and roofing tar and the asphalt coating is deteriorating on many of the dikes, vegetation is encroaching, and some minor sloughing was noted. If not maintained, further erosion may occur to containment dikes and there are potential compliance risk related to 40 CFR 121, SPCC, and WAC173-180-320. A tank containment dike erosion control program is in place but needs to be accelerated to mitigate erosion issues over next three years.

Certain floating roof deck fittings do not meet the requirements of Refinery MACT Subpart CC for storage tanks. According to TRMC representatives, seals/gaskets need to be replaced on 27 tanks in the Assets covered by the 2017 Anacortes Contribution Agreement.

Per the Consent Decree mentioned in Schedule 1, the Refinery must install closed-purge, closed-loop, or closed-vent samplers at all storage tanks by 2021. According to facility representatives, there are 42 tanks left to retrofit in the Assets covered by the 2017 Anacortes Contribution Agreement.

Severalout-of-service assets are included in the drop, including 17 tanks, the asphalt loading rack, pipelines, the red dye shed, and lead shed areas. TRMC has indicated a total of 17out-of-service tanks (Tanks 34, 46, 47, 48, 55, 62, 88, 89, 90, 95, 98, 99, 110, 147, 159, 232, and 249).

Schedule II- Page 9 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Propane and butane vessels were observed to potentially not have drain-away protection that is sized and configured forone-half the largest vessel. A release should be able to drain away from the vessels to prevent further releases, explosions, and fires.

For 2018 Assets Contribution Agreement listed on Schedule VII:

Defined terms used in this portion of Schedule II without definition will have the meaning given such terms in the 2018 Assets Contribution Agreement.

LOS ANGELES REFINERY (CARSON AND WILMINGTON UNITS)

On August 22, 1990, the Los Angeles Regional Water Quality Control Board (RWQCB) issued Cleanup and Abatement Order (CAO)No. 90-121 to Tesoro Refining & Marketing Company LLC (TRMC) for the LARC Refinery Unit. The CAO requires investigation and remediation of lightnon-aqueous phase liquid (LNAPL) on the water table and groundwater containing dissolved-phase petroleum hydrocarbons and methyl tert-butyl ether (MTBE). TRMC operates a LNAPL and groundwater recovery system predominantly along the western boundary of LARC Refinery Unit. LNAPL also is removed from selected wells within the process and tank farm areas via vacuum truck. Other remediation efforts at the LARC Refinery Unit include vapor-phase hydrocarbon extraction from soils and enhancing natural biologic degradation in groundwater. Groundwater and soil remediation and LNAPL removal will be ongoing.

Subsurface environmental investigation at the LARW Refinery Unit began in the early 1980s. These investigations revealed soil and groundwater impacts from dissolved petroleum hydrocarbons, MTBE, tert-butyl alcohol (TBA) and LNAPL. Shell Oil Products US (SOPUS) is responsible for soil and groundwater remediation originating prior to May 2007. SOPUS has recovered LNAPL using a total fluids extraction system and tracked LNAPL recovery rates since 2010. A Remediation Feasibility Study was submitted by SOPUS to the RWQCB in August of 2017. SOPUS presented four “remedy packages” to meet remedy objectives; however, additional data are needed prior to designing a total fluids extraction or dual pump liquid extraction. Releases from TRMC operations have not commingled with impacts attributable to SOPUS.

Groundwater impacts at the LARC Refinery Unit and the LARW Refinery Unit have migrated downward and offsite. SOPUS, TRMC and Kinder Morgan have modeled groundwater flow and continue to document natural biodegradation in the lower aquifers.

On January 4, 2010, TRMC notified the California Emergency Management Agency of a naphtha release from LARW Refinery Unit Tank 80214. The release was initially estimated at 15,200 barrels. The RWQCB issued CAOR4-2011-0037 to TRMC on April 11, 2011. The CAO required the assessment and delineation of soil and groundwater impacts associated with this release. In response, TRMC investigated the Tank 80214 area and constructed a LNAPL and groundwater extraction system, which is under continuous operation. Remedial efforts areon-going, however active pumping is expected to be complete within 10 years.

Schedule II- Page 10 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Underground piping is to be removed/decommissioned under Cleanup Abatement Order (CAO), Los Angeles Plant (FileNo. 85-20) issued by the California Water Quality Board, Los Angeles Region Order88-70 was adopted June 27, 1988. Between 2003 and 2017, approximately 89,895 feet of aboveground pipeline was installed and approximately 69,182 feet of underground pipeline was decommissioned. Additional underground piping must be removed under this program.

MANDAN REFINERY

On October 16, 2018 the North Dakota Department of Health (NDOH) issued a RCRA Hazardous Waste Storage and Treatment and Corrective Action Permit(HW-002) for operations at the Mandan Refinery. The Permit requires the investigation and mitigation of hazardous wastes and hazardous waste constituents released from facility waste management units, including the wastewater collection system below areas of refinery operations and petroleum storage. Mitigation measures include collecting groundwater from down-gradient recovery trenches and monitoring groundwater twice per year. Continued groundwater monitoring, operation of the groundwater trench collection system, and annual reporting to the NDOH is expected to beon-going.

SALT LAKE REFINERY

TRMC operates a remediation system to contain and recover LNAPL and groundwater at the Salt Lake Refinery. This recovery and monitoring system is operated under a Stipulated Consent Order (SCO), dated January 9, 1992, between the Utah Solid and Hazardous Waste Control Board and Amoco Oil Company, the former refinery owner. Under the SCO, Amoco completed a RCRA Facility Investigation and developed a Corrective Action Plan (CAP) that included a groundwater remediation/containment system, tracking of soil impacts and establishing deed restrictions to limits property and groundwater use. The LNAPL extraction system operates primarily along the western boundary of the refinery, including the west side of the storage tank area. Dissolved petroleum hydrocarbons are no longer detected in site groundwater. As a result, TRMC is currently in discussions with the State of Utah Department of Environmental Quality, Division of Waste Management and Remediation Control, to update the SCO and CAP into a Site Management Plan and Environmental Covenant. It is unknown whether the State will agree with TRMC’s proposed and revised technical approach.

Asphalt seeps within the bermed area at Tank 204 can impact operations within the containment area. The Salt Lake Refinery is currently removing residual pockets of asphalt through routine maintenance. The asphalt has not migrated through the containment area. Asphalt seeps are not expected to infiltrate through soils to the water table. Groundwater from monitoring wells located near Tank 204 do not contain dissolved petroleum hydrocarbons or LNAPL.

Schedule II- Page 11 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

LNAPL and water have been observed within the secondary containment at Tank 247. The wastewater treatment facility capacity at the Salt Lake Refinery can be overwhelmed following heavy precipitation events. The backup of hydrocarbon containing wastewater into the tank berm area reduces the secondary containment capacity and could result (temporarily) innon-compliance with the SPCC requirements. Impacts to groundwater and soil from pooled wastewater and LNAPL are unknown and could require additional remediation.

Laboratory instruments containing free-phase mercury were once used within the Bulk Loading Rack (BLR) Control Building. Impacts from this practice were discovered on December 1, 2014. The free phase mercury in soil was remediated in the immediate area of the BLR, and interior floors were cleaned and sealed. Mercury remains in the shallow soil surrounding the north side of the BLR Control Building; however institutional controls – including an asphalt cap—are in place to prevent earthwork or disturbing the area without approval and permitting. Post-remediation indoor air sampling demonstrated that the BLR Control Building is suitable for worker occupancy.

JAL NGL STORAGE FACILITY

The facility records at the JAL NGL Storage Facility include the following information regarding releases, impacts or potential impacts:

A former compressor unit leaked an unknown quantity of oil containing poly-chlorinated biphenyls (PCBs).

The southwest corner of the property is used for construction debris, out of service equipment, transformers and storage of other discarded materials. Contaminated soil also is placed in this area.

Groundwater is impacted by former operation of brine ponds. Kinder Morgan is responsible for these groundwater impacts.

Wastes, including water, solids, and lubricating oils, were previously disposed in anon-site injection well.

WINGATE TERMINAL

In 2015, the New Mexico Oil Conservation Division issued Abatement PlanAP-121 to Western Refining. Site groundwater impacts will be addressed after the facility is closed or if contamination migratesoff-site. Until closure of the facility’s active operations, theAP-121 requires monitoring eight wells and submitting a report each year. Groundwater monitoring and annual reporting is expected to beon-going.

Asbestos is present at the Wingate Terminal, including buildings that are cladded in transite and pipes insulated with asbestos wrap. Currently, asbestos is kept sealed and managed in place.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Two burn pits were used before the existing flare system was constructed. Flare pits may be a source of surface and subsurface soil impacts.

STATELINE NM TERMINAL

A sump was reportedly overfilled on March 8, 2018 due to a power outage. This caused a release of 24.4 bbl of crude oil, which flowed across the terminal property and to adjacent undeveloped ranch land. Remedial actions are in process.

Schedule II- Page 13 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule III

Pending Litigation

For Initial Contribution Agreement listed on Schedule VII:

None.

For Amorco Contribution Agreement listed on Schedule VII:

None.

For Long Beach Contribution Agreement listed on Schedule VII:

None.

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

None.

For West Coast Assets Contribution Agreement listed on Schedule VII:

None.

For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

None.

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

KENAI TANKAGE:None.

ANCHORAGE AND FAIRBANKS TERMINALS:None.

For Martinez Assets Contribution Agreement listed on Schedule VII:

None.

Schedule III- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

The Additional Indemnification provisions in Article VI of SERA supersede in their entirety the indemnification provisions of Section 3.5(a) of the Fourth Amended and Restated Omnibus Agreement, and shall be the exclusive provisions for all indemnification obligations relating to the subject matter of the indemnities so provided in of Section 3.5(a) of the Fourth Amended and Restated Omnibus Agreement.

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

None

For 2018 Assets Contribution Agreement listed on Schedule VII:

Great Northern Gathering & Marketing LLC vs. Mountain Peak Builders, LLC, Case No.27-2015-CV-00222, District Court, McKenzie County, North Dakota;Mountain Peak Builders, LLC vs. Great Northern Gathering & Marketing LLC, Case No.4:15-cv-034, the United States District Court of North Dakota;Cross-Country Pipeline Supply Co., Inc. v. Great Northern Gathering & Marketing LLC and Great Northern Midstream LLC, Civil Case No.27-2017-CV-00305, in the District Court, McKenzie County, North Dakota. Three related suits regarding construction liens on certain Tesoro Great Plains MidstreamLLC assets in North Dakota relating to workfor the prior owner (all fully indemnified and being defended by third party/seller—secured by escrow).

Efrain Onsurez v Rangeland Energy—Litigation in which plaintiff claims that Rio Pipeline (fka Rangeland) drivers are trespassing on his land and related grievances. Affects Rio Pipeline assets in Texas and New Mexico.

Other litigation scheduled on Schedule I (Environmental Litigation).

The following HR lawsuits and pending administrative claims:

(a)

Lawsuits:

Wuestenfeld v. Rangeland – Former contractor at Rio Pipeline (fka Rangeland) (Midland Terminal) alleges sex harassment and retaliation.

LAR:

Valliere/Bonner v. TRMC—Class action lawsuit alleging failure to provide compliant rest periods and associated Labor Code violations.

Kairn v. TRMC—Two lawsuits, one in state court and one in federal court. Kairn alleges gender discrimination in the state court case, which is scheduled to go to trial in November 2018. The federal court case alleging gender discrimination and retaliation is stayed.

Schedule III- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Tate vs. Tesoro Corp—Complaint names Tesoro Corporation on a joint employment theory and the putative class is defined as including a subclass of Brinderson class members who worked at a refinery owned by Tesoro in California (which would cover the LARW Refinery Unit and the LARC Refinery Unit). Tesoro is indemnified by Brinderson.

(b)

Administrative Charges:

Mandan Refinery:

Sprague—former contractor alleges he was discriminated against due to his disability.

Salt Lake Refinery:

McArthur—former SLC refinery employee alleges sexual harassment, age discrimination, and retaliation.

LARC/LARW Refinery Units:

Davis—Employee alleges that he was not offered a pipefitter position due to discrimination based on race.

McGhee—Employee alleges he was terminated due to his disability.

Wanis—Employee alleges his termination was discriminatory on the basis of race, ancestry, national origin and religion.

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Schedule IV

Section 4.1(a): General and Administrative Services

(1)	Executive management services of Andeavor employees who devote less than 50% of their business time to the business and affairs of the Partnership, including stock based compensation expense

(2)	Financial and administrative services (including, but not limited to, treasury and accounting)

(3)	Information technology services

(4)	Legal services

(5)	Health, safety and environmental services

(6)	Human resources services

Section 4.1(c)(vii): Other Reimbursable Expenses

For Initial Contribution Agreement listed on Schedule VII:

None.

For Amorco Contribution Agreement listed on Schedule VII:

None.

For Long Beach Contribution Agreement listed on Schedule VII:

None.

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

None.

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

None.

Schedule IV- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For West Coast Assets Contribution Agreement listed on Schedule VII:

None.

For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

None.

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

KENAI TANKAGE:None.

ANCHORAGE AND FAIRBANKS TERMINALS:None.

For Martinez Assets Contribution Agreement listed on Schedule VII:

None.

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

None

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

None

For 2018 Assets Contribution Agreement listed on Schedule VII:

None

Schedule IV- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule V

ROFO Assets


Asset		Owner

*Nikiski Dock and Storage Facility (Nikiski, Alaska)* A single-berth dock and storage facility located at the Kenai Refinery that includes five crude oil storage tanks with a combined capacity of approximately 930,000 barrels, ballast water treatment capability and associated pipelines, pumps and metering stations. The dock and storage facility receives crude oil from marine tankers and from local production fields via pipeline and truck, and also delivers refined products from the refinery to marine vessels.		Tesoro Alaska

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Schedule VI

Existing Capital and Expense Projects

For Initial Contribution Agreement listed on Schedule VII:

Expense Projects

None.

Capital Projects

1. That certain project related to AFE # 102120001, which provides for side stream ethanol blending into all gasoline at the Salt Lake City terminal by adding truck ethanol unloading capability, utilizing the existing premium day tank for ethanol and delivering premium direct from the Salt Lake City refinery tankage. New ethanol truck unloading facilities will be installed. New Pumps will also be installed for delivering higher volumes of premium gasoline from the Salt Lake City refinery to the Salt Lake City terminal. An ethanol injection skid will be installed along with piping changing to the existing Salt Lake City terminal to allow the ethanol to be injected in the gasoline stream. This project has been completed.

2. That certain project AFE# 112120005 at the Mandan refinery, to update additive equipment to allow the offering of Shell additized gasoline. This project has been completed.

3. That certain project related to AFE # 107120005, which provides for ratio ethanol blending into gasoline on the rack at the Burley, Idaho Terminal by adding truck ethanol unloading capability, adding tankage for ethanol storage and installing new ethanol meters associated with each gasoline loading arm. New ethanol truck unloading facilities will also be installed.

4. That certain project AFE#104100015-M at the Mandan refinery, to update the truck rack sprinkler system. This project has been completed.

5. That certain project number AFE# 122120002 (TCM Idea# 2010113017) at the Mandan refinery, to upgrade the rack blending hydraulic system to reduce/eliminate inaccurate blends at the load rack.

6. That certain project number TCM Idea # 2011433001 at the Mandan refinery, to move the JP8 to new bay and have three bays for loading product across the rack. This project has been cancelled.

7. That certain project number TCM Idea # 2011432602 at the Stockton terminal, install a continuous vapor emission monitor on the vapor recovery unit for compliance with air quality regulations.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Amorco Contribution Agreement listed on Schedule VII:

Expense Projects

All major expense projects that are within the scope of open Work Orders as of the applicable Closing Date.

Capital Projects

1. That certain project related to AFE# 097100014 and AFE# 107100014 at the Amorco terminal, which provide repairs and upgrades to the wharf regarding MOTEMS standards.

2. That certain project related to AFE# 112100001 at the Amorco terminal, which installs a jet mixer system for crude lab testing.

For Long Beach Contribution Agreement listed on Schedule VII:

Expense Projects

1. Any cost that may be incurred to adjust diesel fuel tank vents near light fixtures after a review is conducted and if action is deemed necessary.

2. Costs related to substantial repair or replacement project scheduled for 2012 and 2013 for the pipeline segments in the portion of the Southern California Edisonright-of-way area immediately adjacent to the marine terminal to address corrosion, and include IO# 3021407 titled “SCA Wilmington Edison Reroute” and IO# 3021749 titled “SCA. Edison Reroute 24 inch, 16 inch, 14 inch”.

Capital Projects

1. That certain project related to AFE# 072104079LBT titled “UG Piping – LBT” related to underground pipeline repairs at the Terminal. In addition, any subsequent new projects to address the same specific under-ground piping issues per AFE# 072104079LBT (i.e. a second phase UG Piping project) that would occur on or before the end of year 2015.

2. That certain project related to the TCM Idea# 2012433432 AFE# 125120020 titled “LBT Berth 84a Loading Arm Replacement” which repairs or replaces the loading arms at the Terminal and any related AFE project that will occur upon final project approval to substantially repair or replace the loading arms at the Terminal.

3. That certain project related to the TCM Idea# 2012433433 AFE# 125120021 titled “LBT Berth 86 Loading Arm Replacement” which repairs or replaces the loading arms at the Terminal and any related AFE project that will occur upon final project approval to substantially repair or replace the loading arms at the Terminal.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

4. Any remaining costs of those certain projects related to the leak detection on the Terminal and Terminal Pipelines which are substantially complete and include AFE# 107110002, AFE# 117110001, AFE# 117110003, AFE# 117110002, and AFE# 125120002.

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

Expense Projects

None.

Capital Projects

Any capital costs or expenses that may be incurred for the installation of a custody transfer meter related to the AFE# 125120017 titled “CROF Custody Transfer Meter and Station”.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

Expense Projects

Expenses associated with the API 653 internal inspection, the Carson Crude Terminal Tank 401 (AFE# 13E1219120001BP/WBS 19125.E012.975) scheduled to start in November 2013, including without limitation, cleaning of such Tank (including any waste removal) and any repairs to such Tank required as a result of such inspection.

Capital Projects

None.

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

Expense Projects

1. All 2013 and 2014 costs related to AFE#136104215BP-M (PRISM ID 32503) for a partial replacement of Rhodia Sulfuric Acid Line 29 will be reimbursed by TRMC to cover the 2014 expenditure of $1.1 million for line neutralization, the pig run andtie-ins. Subject to confirmation with the refinery on exact outage dates, the bulk of this cost will be incurred in March and April.

2. All 2013 costs or 2013 carry-over costs related to AFE#13E1012000002BP-M12 &13E1012000002BP-M5 PRISM ID 32518 (under the 2013 AFE # 13E1012000002BP) for the Manual Entry Corrosion Program at Terminal 2 will be reimbursed by TRMC. All 2014 costs will be covered by the Partnership’s 2013 budget.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

3. All remaining 2013 inspection and repair costs related to AFE#13E1012000002BP-M2 (PRISM ID 32549) associated with the Marine Terminal 2 – TK 218 – API 653 Internal Inspection only (not including repairs at this point) will be reimbursed by TRMC. TRMC shall review and approve the tank repair scope and review inspection reports to prevent unnecessary upgrades or “urban renewal.”

4. All remaining 2013 inspection and repair costs related to AFE#13E1212000001-M (PRISM ID 31418) associated with the Marine Terminal 2 – TK 205 – API 653 Internal Inspection only (not including repairs at this point) will be reimbursed by TRMC. TRMC shall review and approve the tank repair scope and review inspection reports to prevent unnecessary upgrades or “urban renewal.”

5. Remaining expenses related to AFE#13E1179000001-M (PRISM ID 32040) to upgrade PLC systems in the LA Basin will be reimbursed by TRMC.

6. All remaining 2013 inspection and repair costs related to AFE#13E1212000002-M (PRISM ID 31419) associated with the Marine Terminal 2 – TK 217 – API 653 Internal Inspection only (not including repairs at this point) will be reimbursed by TRMC. TRMC shall review and approve the tank repair scope and review inspection reports to prevent unnecessary upgrades or “urban renewal.”

7. All remaining expenses related to AFE#136104222BP-M (PRISM ID 32556) associated with the Pipeline OQ Verification will be reimbursed by TRMC.

8. All remaining 2013 inspection and repair costs related to AFE#13E1012000006-M (PRISM ID 31409) associated with the Carson Products – TK VH1 – API 653 Inspection only (not including repairs at this point) will be reimbursed by TRMC. TRMC shall review and approve the tank repair scope and review inspection reports to prevent unnecessary upgrades or “urban renewal.”

Capital Projects

1. Maintenance capital expenditures related to that certain AFE#136104194BP-M (PRISM ID 32480) at Terminal 2 to replace all fire water piping at Berths 76, 77 and 78 areas of Terminal 2 in Long Beach, CA with new piping. This project will also replace all associated valves, fixtures, monitors, and fire-fighting accessories.

2. Maintenance capital expenditures related to that certain TCM Idea# 2013434229 (PRISM ID 25829) at Terminal 2 to replace the existing bladder type foam tank with two atmospheric tanks and foam skids located at either end of the facility along with new piping to support the installation.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

3. Maintenance capital expenditures related to that certain TCM Idea# 2013434243 (PRISM ID 20054) at Terminal 2 to replace the existing loading arms at T2’s Berth 77 and 78. The current parts are so old that they are no longer readily available, so in order to properly maintain this equipment to minimize down-time for repairs, these arms should be replaced with the newest models.

4. All capital expenditures related to that certain AFE#136104077BP-M (PRISM ID 32481) for MOTEMS dock side piping upgrades at Terminal 2.

5. Maintenance capital expenditures related to that certain AFE# 145120008 (PRISM ID 32560) at Terminal 2 to replace the main 12kV electrical switchgear that experienced electrical damage due to several factors: nearing its equipment service life, component degradation, exposure to the elements. The main copper busbar component of the switchgear was recently replaced and dipped in epoxy coating. However, during the repairs, cracks on the insulation of the main horizontal operating bus were discovered. The exterior enclosure is slowly showing signs of corrosion and the glastic insulation materials are degrading.

6. Upon TRMC’s approval to complete the following projects, all capital costs incurred to connect the Los Angeles Wilmington and Carson refinery systems, as well as the crude and product pipeline systems: TCM Idea# 2013434786, AFE#132110022-M (TCM Idea# 2013434419), TCM Idea# 2013434788, AFE#132110023-M (TCM Idea# 2013434417), AFE#132110025-M (TCM Idea# 2013434418), AFE#132110030-M (TCM Idea# 2013434420), AFE#132110031-M (TCM Idea# 2013434784), TCM Idea# 2013434785 and AFE# 132110026 (TCM Idea# 2013434137).

7. Upon TRMC’s approval to complete the project, all capital costs related to the project at Terminal 2 targeted to reduce Andeavor’s demurrage cost due to barge delivered additive alternative, under AFE#132110024-M (TCM Idea# 2013434220).

8. All capital costs related to AFE# 131907046, the implementation of an equivalent solution using Andeavor ECC 6 MOC module, including necessary configuration changes and customization of interfaces to be completed and executed in line with other transformation projects identified as part of integrating other BP assets such as TMS5 to DTN Guardian3, Load Tracker, etc. in the Logistics area.

9. All capital costs related to AFE# 131907047. As a part of the BP Carson Tranche 1 Contribution Agreement, Andeavor acquired Maximo,i-Maintain, Maximo Mobile and Primavera. These applications are used for scheduling and managing routine maintenance tasks and planning capital projects (Primavera). These business functions will be transitioned to SAP PM (using GWOS) and a TSO instance of Primavera. This initiative should be performed in line with Maximo to SAP PM transformation project and with other logistics and refining projects.

Schedule VI- Page 5 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

10. All capital costs related to AFE# 131907045. This project, in conjunction with Andeavor’s acquisition of the BP Carson City Refinery, is designed to transition and successfully integrate the Southwest’s Logistics Mechanical Integrity Inspection System Information Technology assets into the Andeavor Information Technology application landscape.

For West Coast Assets Contribution Agreement listed on Schedule VII:

Expense Projects

1.Nikiski Terminal. Tesoro Alaska shall reimburse the Partnership Group for any costs or expenses incurred by the Partnership Group to reinstate water supply to the Operating Company’s Nikiski Terminal in connection with the water suppression system.

2.Anacortes Light Ends Rail Facility.TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group:

•

to determine the adequacy of fire water at the facility;

•

with respect to any modifications needed to be made to fire water system to provide adequate fire water; and

•

for relocation of the knockout drum, if relocation is required.

3.Anacortes Storage Facility

•

TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group to restore Tank 135 to API 653 specifications. TRMC shall be deemed to be the generator of all hazardous waste and other waste removed from Tank 135 in connection with such cleaning and restoration and shall be responsible for all obligations arising as the generator of such hazardous waste and other waste.

•

TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group for decommissioning and repair of sewer lines for Tanks 165 and 166.

4.Martinez Light Ends Rail Facility. TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group:

•

to determine the adequacy of fire water at the facility; and

•

with respect to any modifications needed to be made to fire water system to provide adequate fire water.

5.Martinez Clean Products Truck Rack. TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group:

•

if required to supplement data currently available in the baseline inspections records in order to properly document corrosion, to carry out new tank corrosion inspections on Tanks 777, 778 and 890, as well as any repairs resulting from such inspections to meet API 653 standards; and

Schedule VI- Page 6 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

•

with respect to Tank 777, the tank berm size and tank proximity evaluation scheduled to completed byyear-end 2014, as well as any required adjustments resulting therefrom.

6.Martinez Light Ends Storage. If required to supplement data currently available in the baseline inspection records in order to properly document pipe integrity, TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group for inspections and analyses conducted to confirm baseline pipe integrity byyear-end 2014, as well as any repairs arising from defects identified through such inspections.

7.Tesoro Alaska Pipeline

•

Andeavor shall reimburse the Partnership Group for any costs or expenses incurred by the Partnership Group to carry out the repairs and tests identified in the Coffman Engineers report dated May 8, 2014, including the planned hydro-test in 2015 and any resulting repairs therefrom.

•

Andeavor shall reimburse the Partnership Group for any costs or expenses incurred by the Partnership Group to carry out repairs identified pursuant to the inspection on the Tesoro Alaska Pipeline as a result of the inspection scheduled to begin June 30, 2014.

Capital Projects

Martinez Capital Projects

1. All capital costs related to AFE# 127100012—Design, procure, and install Biodiesel Blending Facility at existing Martinez Tract 3 Truck Loading Rack.

2. All capital costs related to AFE# 132100017 – Martinez gasoline loading rack filtration.

3. All capital costs related to AFE# TBD regarding Fall Protection for Top Loading Tank Cars and Trucks.

4. All capital costs related to AFE# 132100017 regarding the installation of a new Tract 3 Gasoline Loading Rack Filtration System to replace the existing rental units.

5. All capital costs related to AFE# PTS 12475 regarding LPG Tank Car Loading Rack Improvements.

6. All capital costs related to AFE# TBD regarding the installation of a system to add ExxonMobil additives to gasoline at the Tr. 3 truck loading rack.

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Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

7. All capital costs related to AFE# 145110009 regarding the implementation of Tesoro Alaska Pipeline mainline delivery strainer.

Alaska Capital Projects

1. All capital costs related to AFE# 125100055—Additive reservoir tank and pumping system for the Nikiski Terminal truck loading rack.

2. All capital costs related to AFE# 125110005—Fabrication and installation of a skid-mounted clay treatment system at the Tesoro Alaska Pipeline Port of Anchorage delivery facility.

3. All capital costs related to AFE# 125110007 – Provision of inline strainers upstream of the Kenai Pump station pipeline pumps and upstream of the Anchorage receiving station control valve.

4. All capital costs related to AFE# 124100034—Purchase and installation of (5) IP CCTV Cameras, and security video monitoring station for Tesoro Alaska Pipeline Anchorage control room (located at the Port of Anchorage Industrial Park), MLV 7 on Northern Lights Blvd, and the ASIG Filter Building located at Ted Stevens International Airport.

5. All capital costs related to AFE# 145110002 regarding the installation of semi-deep cathodic protection wells, a new rectifier and electrical service at the Tesoro Alaska Pipeline.

6. All capital costs related to AFE# 124100030 regarding new CCTV monitoring system at the Nikiski Terminal.

7. All capital costs related to AFE# 145120005 regarding a new cathodic protection anode bed and rectifier for the Nikiski Terminal.

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For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

Capital Projects

TRMC shall reimburse the Partnership Group for:

1. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following piping systems projects: AFE# 136104160BP (TCM Idea# 2013218160), TCM Idea# 2013212538, TCM idea# 2013212540 and TCM Idea# 2013212539. For any such projects listed above in this section 1 that are required to maintain safe operation of the Assets, the Partnership shall determine the final project scope in its sole discretion.

2. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following instrumentation and control projects: AFE# 154100014 (TCM Idea# 2014217001), TCM Idea #2014217008, AFE# 136104169BP (TCM Idea# 2013218169), AFE# 136104190BP (TCM Idea# 2013218190), TCM Idea# 2013212558, and TCM Idea # 2014217023. For any such projects listed above in this section 2 that are required to maintain safe operation of the Assets, the Partnership shall determine the final project scope in its sole discretion.

3. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following tank improvements: TCM Idea# 2014217135 (tk 56), TCM Idea# 2013212585 (tk 1), TCM Idea# 2014217132 (tk 90), TCM Idea# 2014217133 (tk 11), TCM Idea# 2013212575 (tk 34), TCM Idea # 2013212587 (tk 35), TCM Idea# 2013212588 (tk 10), TCM Idea# 2013212589 (tk 58), TCM Idea# 2013212592 (tk 39), TCM Idea# 2013212593 (tk 968), TCM Idea# 2013212595 (tk 60), TCM Idea# 2013212596 (tk 69), TCM Idea # 2013212597 (tk 57), TCM Idea# 2013212599 (tk 51). For any such projects listed above in this section 3 that are required to maintain safe operation of the Assets, the Partnership shall determine the final project scope in its sole discretion.

4. All capital costs related to the repair or replacement of brick structure piping supports, with the scope of repairs to be developed in 2016 and the execution of such repairs to be completed in 2017.

5. All capital costs related to the upgrade or replacement of the cathodic protection system for the tanks as identified through a cathodic protection assessment to be completed prior to year end 2016. An action plan will be developed to address recommendations identified through the assessment. The program is expected to commence in 2016 and will be executed over a4-year period.

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6. All capital costs related to the multi-phase upgrade or replacement of tank level measurement and transmitter instruments, upon mutual consent of TRMC and the Partnership of the scope for the multi-year project. Notwithstanding the foregoing, the Partnership in its sole discretion shall determine the final scope of any element of the tank level instrument upgrade project required to maintain safe operation of the Assets. TRMC’s reimbursement to the Partnership Group for capital costs incurred during the Term to complete the tank level instrument upgrade or replacement project shall not exceed $15,000,000 in the aggregate.

Expense Projects

1. With respect to the Remaining Pipeline 88 Interest (as defined in the 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII), TRMC shall reimburse the Partnership for any costs and expenses associated with curing any anomalies identified by the August 2015in-line inspection thereof.

2. With respect to the Tankage (as defined in the 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII), as well as the land on which such Tankage is located, TRMC shall reimburse the Partnership for any costs and expenses associated with any liabilities, costs and expenses that might be imposed upon the Partnership as operator of the Tankage and which relate to the environmental condition of the land on which the Tankage is located and surrounding lands, including but not limited to any government-imposed fines or remediation costs and natural resource damages, but excluding (i) any liabilities, costs and expenses that arise from any releases or discharges of hydrocarbons or other substances from the Tankage after the date hereof or (ii) any liabilities, costs and expenses that arise from negligent acts or omissions or willful misconduct of the Partnership and its agents, contractors and representatives.

3. Until the later of (i) November 12, 2020 or (ii) the completion of any repairs identified by any applicablenon-invasive or external inspections that occurred prior to such date, TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group to restore any tank included in the 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII to API 653 or API 510 specifications that are identified through the Partnership Group’snon-invasive or external inspections.

4. During the term (including any extension thereof) of the Carson II Storage Services Agreement, dated as of November 12, 2015, by and among TRMC, the General Partner, the Partnership and the Operating Company (the “Carson II Storage Agreement”), TRMC shall reimburse the Partnership Group for any costs and expenses incurred by the Partnership Group to restore any tank included in the 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII to API 653 or API 510 specifications, as determined by the results of the first scheduled internal inspection of any such tank after the date hereof (the “First Internal Inspection”). TRMC shall be deemed to be the generator of all hazardous waste and other waste removed from any such tanks in connection with such cleaning and restoration and shall be responsible for all obligations arising as the generator of such hazardous waste and other waste.

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TRMC and the Operating Company shall mutually agree on the inspection schedule and the duration of such inspections so as to minimize disruption within the Wilmington and Carson refinery systems, with TRMC having the right to approve the final inspection schedule.

If TRMC fails to renew the Carson II Storage Services Agreement, prior to November 12, 2022, in accordance with the terms thereof, the Partnership Group may elect to accelerate API 653 or API 510 inspections prior to the expiration of the Carson II Storage Agreement.

5. Notwithstanding Sections 3 and 4 above, the parties agree that the following tanks included in the 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 24 months prior to the date of that Contribution Agreement, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of TRMC:


Tank Number		Year of Last Inspection
53		2013
87		2013
41		2013
4		2013
88		2013
5		2013
24		2013
325		2013
326		2013
45		2014
65		2014
89		2014
276		2014
289		2014
303		2014
340		2014
50		2014
302		2014
138		2014
139		2014
289		2015
65		2015
969		2015
40		2015
955		2015
194		2015

Schedule VI- Page 11 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

KENAI TANKAGE:

Capital Projects

TAC shall reimburse the Partnership Group for:

Upon mutual consent on project scope between TAC and the Partnership, TAC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following instrumentation and control projects: AFE# 2012217023 (TCM Idea# 137100002), TCM Idea# 2014216018, TCM Idea# 2007002425. For any such projects listed above in this section 1 that are required to maintain safe operation of the Assets, the Partnership shall determine the final project scope in its sole discretion.

All capital costs related to the assessment and upgrade or replacement of tank level measurement and transmitter instruments, upon mutual consent of TAC and the Partnership of the scope for the multi-year project. Notwithstanding the foregoing, the Partnership in its sole discretion shall determine the final scope of any element of the tank level instrument upgrade project required to maintain safe operation of the Assets.

All capital costs related to installation of tank liners during first API 653 inspection cycle to bring each tank into conformance with Alaska Department of Environmental Conversation standards.

All capital costs related to the assessment and necessary upgrades of cathodic protection system including:

•

Additional anode ground beds

•

Additional surface distributed anodes

•

Additional amperes of cathodic protection foron-grade storage tanks

•

Under tank monitoring systems

The program is expected to commence in 2016 and will be executed over a3-year period.

All capital costs related to internal inspection, assessment and repair of Tank 11 internal floating roof.

Expense Projects

The parties agree that Tank 37 included in the Alaska Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 24 months prior to the date hereof, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of TAC.

Schedule VI- Page 12 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Any costs or expenses related to:

•

Completion of pressure relief documentation, expected to be complete byyear-end 2016.

•

Completion of area classification plans per NEC 500.4, expected to be complete byyear-end 2017.

ANCHORAGE AND FAIRBANKS TERMINALS:

Capital Projects

TAC shall reimburse the Partnership Group for:

All capital costs related to:

Anchorage Terminal

•

Installation of permanent fire water pipeline supports with proper coating; expected to be complete byyear-end 2017.

•

Assessment, evaluation and potential replacement of two deep anode ground beds (No. 2 and No. 5); expected to be completed within cathodic protection program byyear-end 2018.

•

Installation of third tank floor on Tank 4236 with either new cathodic protection system or an El Segundo system; expected to be complete byyear-end 2020.

•

Assessment and upgrades to add access platforms and roof protection to east side filter vessels; expected to be complete byyear-end 2017.

Fairbanks Terminal

•

Assessment, evaluation and potential replacement of two deep anode ground beds and installation of two new rectifiers to allow ground beds to be operated independently; expected to be completed within cathodic protection program byyear-end 2018.

Expense Projects

Any costs or expenses related to:

Anchorage Terminal

•

Inspection and assessment of buried product pipeline; expected to be complete byyear-end 2017.

•

Assessment of manual operation of rail car sump tankage; expected to be complete byyear-end 2017.

Fairbanks Terminal – Any costs or expenses related to:

•

Arc flash assessment; expected to be complete byyear-end 2017.

Relief valve sizing and selection assessment; expected to be complete byyear-end 2017.

Schedule VI- Page 13 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Martinez Assets Contribution Agreement listed on Schedule VII:

Capital Projects

TRMC shall reimburse the Partnership Group for:

1. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following secondary containment projects identified for Tract 3 and Tract 6: AFE# 127100010 (TCM Idea# 2007000713), TCM Idea# 2012211027. In addition, TRMC shall reimburse the Partnership for any additional capital costs or expenses that are associated with the regulatory mandated validation of secondary containment volumes for the Spill Prevention Controls and Countermeasures Plan. For any such projects listed above in this section 1 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

2. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following tank repairs, improvements and new build projects: AFE# 152100015 (TCM Idea# 2007000694), TCM Idea# 2007000701, TCM Idea# 2009001043, TCM Idea# 2012211055, TCM Idea# 2012211056, TCM Idea# 2012211080, TCM Idea# 2012211082, TCM Idea# 2013211049, TCM Idea# 2013211073, TCM Idea# 2014211011, TCM Idea# 2014211038, TCM Idea# 2014211040. For any such projects listed above in this section 2 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

3. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the Avon Warf Upgrade project (MOTEMS), AFE# 077100030 (TCM Idea# 2007001314), and the Avon Wharf Pipeline Surge Protection project, AFE # 154100001 (TCM Idea # 2012211075). In addition, TRMC shall reimburse the Partnership for any additional capital costs or expenses that are determined to be required to bring the Avon Wharf into compliance with MOTEMS at the time of the commencement of service of the replacement Wharf, but not for future MOTEMS that may be imposed after the replacement Wharf is approved and permitted for operation. For any such projects listed above in this section 3 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

4. Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following miscellaneous projects: TCM Idea# 2007001600, TCM Idea# 2014211008. For any such projects listed above in this section 4 that are required to maintain safe operation of the Assets, the Partnership shall determine the final project scope in its sole discretion.

5. All capital costs related to the replacement and associated initial permitting requirements of the Marine Vapor Control System.

Schedule VI- Page 14 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

6. All capital costs related to the upgrade or replacement of the cathodic protection system for the tanks as identified through a cathodic protection assessment. An action plan will be developed to address recommendations identified through the assessment. The program is expected to commence in 2017 and will be executed over a4-year period.

7. All capital costs and expenses that may be associated with the Asset Retirement Obligations with respect to the existing Avon Wharf and its berths (but not including any future costs of demolition and retirement of the structures on the replacement Wharf now being constructed).

8. All capital costs and expenses that may be associated with the removal of abandoned pipelines in the Licensed Premises, but only to the extent that such abandoned pipelines have never been used to provide services under the Martinez Storage Services Agreement and such pipelines are then required to be removed pursuant to applicable law, regulation or governmental order.

9. All capital costs and expenses related to the Getty pipeline thermal expansion assessment and potential relocation of the pipeline above ground, per refinery inspection recommendation.

10. All capital costs and expenses related to the assessment and potential repairs to underground storm water piping.

Expense Projects

1. The parties agree that the following tanks included in the Martinez Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 24 months prior to the date of that Contribution Agreement, or the next scheduled tank inspection falls beyond the year 2036, and such tanks are excluded from the reimbursement requirements listed in Section 5.1(a) of this Agreement, unless such actions fail to meet such compliance standards due to the negligence of TRMC.


Tank Number
026
258
517
601
612
641
690
701
702
709
710
711

Schedule VI- Page 15 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Assets owned by Western Refining, Inc. and Western Refining Logistics LP and their subsidiaries prior to the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

None, except as provided under the SERA, which and shall be the exclusive provisions for all such matters provided in the SERA.

Schedule VI- Page 16 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

Capital Projects

TRMC shall reimburse the Partnership Group for:

Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following gasoline blending unit projects identified: TCM Idea# 2017211656, TCM Idea# 2016215025, TCM Idea# 2014215018, and TCM Idea# 2012215056. For any such projects listed above in this section 1 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following tank repairs, improvements and new build projects: TCM Idea# 2015215024, TCM Idea# 2015215023, TCM Idea# 2015215020, TCM Idea# 2015215022, TCM Idea# 2015215006, TCM Idea# 2016215005, TCM Idea# 2015215008, AFE# DTKRS.0600.2017.03 (TCM Idea# 2015215017), AFE# DTKRS.0600.2017.02 (TCM Idea# 2015215018), AFE# DTKRS.0600.2017.01 (TCM Idea# 2015215010), TCM Idea# 2015215019, TCM Idea# 2015215015, TCM Idea# 2015215012, TCM Idea# 2015215026, TCM Idea# 2009005038, AFE# DTKRS.0600.2016.03 (TCM Idea# 2011215042), AFE# DTKRS.0600.2016.05 (TCM Idea# 2009005041). For any such projects listed above in this section 2 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the tank improvement program listed under AFE# 164100007 (TCM Idea# 2015215004). The Partnership, in its sole discretion, shall determine the final scope of the project listed above in this section 3, if required to maintain safe operation and compliance of the Assets.

Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all capital costs incurred for the execution of the following manifest rail unloading project identified: TCM Idea# 2016215023. The Partnership, in its sole discretion, shall determine the final scope of the project listed above in this section 4, if required to maintain safe operation and compliance of the Assets.

Schedule VI- Page 17 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2013215028, AFE#172100086 (TCM Idea# 2014215009). For any such projects listed above in this section 5 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

All capital costs related to the installation of closed-purge, closed-loop, or closed-vent samplers at all storage tanks by 2021 (per the Consent Decree mentioned in Schedule 1). According to TRMC representatives, as recorded in section 2.2.4 of ERM’s Due Diligence Summary Report (October 2017), there are 42 tanks left to retrofit in the Assets covered by the 2017 Anacortes Contribution Agreement.

Expense and/or Capital Projects

The parties agree that the following tanks included in the 2017 Anacortes Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 36 months prior to the date hereof and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of TRMC.

Tank Number

TK001

TK019

TK024

TK025

TK026

TK028

TK060

TK091

TK092

TK134

TK248

TK156

TK158

TK180

TK241 A

TK241 B

Upon mutual consent on project scope between TRMC and the Partnership, TRMC shall reimburse the Partnership Group for all expense and capital costs incurred for the execution of the following miscellaneous projects identified in the tables below.

Schedule VI- Page 18 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Tank Farm Projects

IEA) - Replace aging power poles in Tank Farm

IEA) - Upgrade Switch Racks

IEA) - Tank Farm Conduit

IEA) - Replace MOV’s in the tank farm

IEA) - Replace Coggins Conduit and wire

IEA) - Tank Farm Grounding

IEA) - Install electric heat tracing

PIPE) - Upgrade steam piping in tank farm

REF) - Sample station compliance

IEA) - Skim oil sump level controller toP-709

INSP) - Required inspection work onV-801

INSP) - Required inspection work onTK-38

REF) - Purchase tank 8 heater

TKWK) - Roof Drains, Seal Failures

IEA) - Back pressure regulator for C4 to storage

INSP) - Offsite/Rack Piping RBMI Implementation – Field

Marine Terminal Projects

REF) - Contingency boom replacement

IEA) - Causeway Conduit

PPXX) - Abrasive Blast and recoat wharf lines and remove asbestos conduit

REF) - Rebuild bumpers to be prioritized by operations

WINP) - Install stairway to access spill boats

Rail Projects

RAIL) - Rail Maintenance & Inspection

Rail) - Rail Track Repair

Note, the above projects in this section 2 are characterized by Program and Technical ID or Work Note shown in the Major Special Maintenance (MSM) budget of the Andeavor Anacortes Refinery. For any such projects listed above in this section 2 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

All additional operating expenses associated with accelerating the tank containment dike erosion control program, for the mitigation of erosion issues, over the next five years. This issue is recorded in section 2.2.2 of ERM’s Due Diligence Summary Report (October 2017) as well as section 3.2.1 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

All costs related to the installation of independent high-high level switches, consistent with the established tank inspection and repair program. This issue is recorded in section 3.2.1 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

Schedule VI- Page 19 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

All costs for any future modifications required to comply with Andeavor “Tank & Loading Rack” fire protection standardCPER-004 currently under review. This issue is recorded in section 3.4.11 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

All costs for implementing a surge study for the wharf transfer piping and for any required modifications discovered as a result of this study. This issue is recorded in sections 2.2.1 and 6.2.1 of ERM’s Due Diligence Summary Report (October 2017).

All costs for implementing a study of the dike arrangement to the north and east sides of Tank 38, which may not adequately direct contents to the remote containment area in the event of a vessel failure, and for any required modifications discovered as a result of this study. This issue is recorded in section 3.2.2 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

All costs for potential future expenses of investigation and mitigation work related to seep of oil through the north secondary containment dike for tanks 6 and 7. This issue is recorded in sections 6.1.1 and 6.2.3 of ERM’s Due Diligence Summary Report (October 2017).

All costs related to the installation of storage tank seals and gaskets, required by Refinery Sector Rule MACT Subpart CC, to be identified in the established compliance schedule for tank inspection and repair. This issue is recorded in section 2.2.3 of ERM’s Due Diligence Summary Report (October 2017).

10.

All costs to empty, blind-flange orair-gap any of theout-of-service tanks listed below.

Tank Number

TK034

TK046

TK047

TK048

TK055

TK062

TK088

TK089

TK090

TK095

TK098

TK099

TK110

TK147

TK159

TK232

TK249

Schedule VI- Page 20 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

11.

All costs for removal ofout-of-service assets identified in section 6.2.8 of ERM’s Due Diligence Summary Report (October 2017). These assets include 17 tanks (shown in Section 10 above), asphalt loading rack, pipelines, red dye shed and lead shed.

12.

All costs related to the performing of an assessment of propane and butane vessel containment areas, and any resulting project expenses required, to ensure compliance with National Fire Protection Association (NFPA) fire codes. This issue is recorded in section 6.3.3 of ERM’s Due Diligence Summary Report (October 2017).

13.

All costs related to performing an initial direct assessment, and any resulting required repairs, of the Andeavor-owned segment of the underground “Kinder Morgan” crude pipeline. This issue is recorded in section 3.3.1 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

14.

All costs related to performing an initial inspection, and any resulting required repairs, of the wharf sumps. This issue is recorded in section 3.3.5 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

15.

All costs related to performing an initial inspection, and any resulting required repairs, of the cathodic protection (CP) systems for the aboveground storage tank bottoms, buried facility piping and marine structures. During this inspection the rectifiers will be surveyed and any rectifiers which are not Nationally Recognized Testing Laboratory (NRTL) listed per OSHA (Occupational Safety and Health Administration) and NFPA requirements will be replaced and costs will be subject for reimbursement. These issues are recorded in section 3.4.17 of Coffman’s Mechanical Integrity Due Diligence Study (September 2017).

16.

All cost ofin-service inspections and evaluations of the condition of tank walls and tank floors for each of the following tanks, using accepted engineering methods fornon-invasive external inspections that do not require that a tank be emptied or structurally altered, which are conducted before the earlier of (i) an API 653 inspection of such tank and (ii) November 7, 2022, up to an aggregate reimbursable cost not to exceed two million dollars for all such tanks.

Tank Number

TK003

TK005

TK006

TK008

TK011

TK013

TK015

TK017

TK018

Schedule VI- Page 21 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

TK021

TK022

TK027

TK030

TK032

TK033

TK035

TK036

TK037

TK038

TK113

TK114

TK142

TK148

TK230

TK247

TK054

TK056

TK138

TK160

TK157

TK221

TK222

TK223

TK224

TK225

TK226

TK227

TK228

TK229

Schedule VI- Page 22 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For 2018 Assets Contribution Agreement listed on Schedule VII:

Defined terms used in this portion of Schedule VI without definition will have the meaning given such terms in the 2018 Assets Contribution Agreement.

Capital Projects

The Andeavor Entities shall reimburse the Partnership Group for:

Los Angeles Refinery Wilmington—Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of Partnership Group, the Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:


IDEA#	AFE	DESCRIPTION

NA	LA-130014	RAIL CAR FALL PROTECTION

100000000000000007122018	NA	TANK GAUGING PH V

100000000000000013322018	NA	LAR CATHODIC PROTECTION PROGRAM

100000000000000014342018	NA	RP&S CONTROL SYSTEM MODERNIZATION

100000000000000020072018	NA	REPLACE EAST RAILCAR LOADING PLATFORM

100000000000000042922018	NA	Tank Gauging VII

100000000000000042822018	NA	UPR – LARW

NA	NA	Tank 11001 Double-Bottom Upgrade Project

For any such projects listed above in this section 1 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Los Angeles Refinery Carson—Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:


IDEA#	AFE	DESCRIPTION

NA	LA-160102	70 SERIES BUTANE SPHERE LEVEL MEASUREMENT

NA	LA-180057	PROPANE LOADING ODORANT TRIP

For any such projects listed above in this section 2 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Mandan Refinery—Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the Andeavor

Schedule VI- Page 23 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:


IDEA#	AFE	DESCRIPTION

NA	MN-170096	TANK FIELD MODERNIZATION—PHASE 4

100000000000000013852018	NA	FB-754 NEW CR & INTERNAL FLOATING ROOF CONVERSION

100000000000000013862018	NA	FB-706 NEW CR & INTERNAL FLOATING ROOF CONVERSION

NA	MN-180087	INSTALL SPAREGA-778 PROPANE LOADING PUMP

NA	MN-180084	TANK FIELD MODERNIZATION—PHASE 5

100000000000000020132018	NA	REPLACE OM PLC OR MOVE TO THE DCS

100000000000000020182018	NA	FB-724—NEW INTERNAL FLOATING ROOF

NA	MN-180094	Firewater Line to Rail Switch Yard

NA	MN-180085	Oil Movements HPM Migration

100000000000000041422018	NA	FB-738 Foam Pipe and New Basin

NA	MN-170121	BUTANE TRUCK OFFLOADING

NA	TA-160011	FB-751 DOUBLE FLOOR REPLACEMENT

NA	TA-160013	FB-741 INTERNAL SHELL REPAIR

NA	TA-160014	FB-755 INSPECT AND REPAIR

100000000000000006842018	NA	FB-738—BOTTOM REPAIRS AND BASIN ENHANCEMENT

100000000000000006852018	NA	FB-752—BOTTOM REPAIRS AND BASIN ENHANCEMENT

100000000000000006862018	NA	FB-742—BOTTOM REPLACEMENT

100000000000000006922018	NA	FB-710 Inspect and Repair

100000000000000006932018	NA	FB-726 Inspect and Repair

For any such projects listed above in this section 3 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Salt Lake Refinery - Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:

Schedule VI- Page 24 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


ITEM # (IDEA #)	ID (AFE)	DESCRIPTION

NA	SL-160012	SALT LAKE TIER III GASOLINE COMPLIANCE (Tank 248 + Rail + Dan Upgrades + Blend Upgrades)

NA	SL-170063	TANK 144 REPLACEMENT (new 245)

NA	SL-170004	TANK 245 REPLACEMENT (new 244)

NA	SL-170034	TANK 213

NA	SA-179045	Automation Modernization Program (AMP) (to replace OMD CSM and BLR SIS projects)

100000000000000017312018	NA	DIESEL / JET MANIFOLD SEGREGATION

NA	SL-180011	Modernize Cyber Security Infrastructure

100000000000000027732018	NA	TANK 243 REPLACEMENT

100000000000000006602018	NA	TANK 206 TURNAROUND

100000000000000006612018	NA	TANK 247 TURNAROUND

100000000000000006652018	NA	TANK 246 TURNAROUND

100000000000000006772018	NA	Tank 206(A) New Tank

For any such projects listed above in this section 4 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Delek Asphalt Terminals—Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:


IDEA#		AFE	Location	DESCRIPTION
TBD		TBD	Fernley (50%)	Fall Protection – Truck
TBD		TBD	Fernley (50%)	Fall Protection – Rail
TBD		TBD	Fernley (50%)	Remove surface impoundment
TBD	��	TBD	Elk Grove	Fall Protection – Truck
TBD		TBD	Elk Grove	Fall Protection – Rail
TBD		TBD	Elk Grove	Replace CS RTO lines with SS
TBD		TBD	Elk Grove	Remove surface impoundment
TBD		TBD	Elk Grove	Piping debottleneck
TBD		TBD	Elk Grove	Refurbish PMA unit
TBD		TBD	Mojave	Fall Protection – Truck
TBD		TBD	Mojave	Fall Protection – Rail
TBD		TBD	Mojave	Hot oil booster pump
TBD		TBD	Bakersfield	Fall Protection – Truck
TBD		TBD	Bakersfield	Fall Protection – Rail
TBD		TBD	Bakersfield	Remove surface impoundment
TBD		TBD	Bakersfield	New Boiler/Steam Generator
TBD		TBD	Bakersfield	Hot Water tank
TBD		TBD	Bakersfield	New emission control unit
TBD		TBD	Phoenix	Fall Protection—Truck
TBD		TBD	Phoenix	Fall Protection – Rail
TBD		TBD	System	Spare emulsion mill/housing
TBD		TBD	System	Spare PMA mill tooling

Schedule VI- Page 25 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For any such projects listed above in this section 5 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

BakkenLink / Fryburg - Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified:


IDEA#	AFE	DESCRIPTION

NA	NG-170034	FRYBURG RAIL TERMINAL T103 & T104 VALVE

NA	NG-180026	FRYBURG RAIL TERMINAL SECURITY IMPROVEMENT

NA	NG-180019	TGP METER SKID BUILDING UPGRADES

NA	NG-180020	ARC FLASH MITIGATION TGPM

NA	NG-180021	TANK LIGHTNING PROTECTION TGPM

NA	NG-180022	FLOWCAL IMPLEMENTATION BAKKENLINK

NA	NG-180017	TANK MIXERS T201 AND T301 AT WATFORD CIT

For any such projects listed above in this section 6 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Jal NGL Storage Facility- Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the applicable Andeavor Entities shall reimburse the Partnership Group for all capital costs incurred for the execution of the following projects identified


IDEA#	AFE	DESCRIPTION

TBD	TBD	Dead leg removal project: Remove several dead legs SW of the pump house and reroute a brine water line to mitigate an existing ramp concern

99991944	NA	2019.SMT.Jal NGL Storage Facility. Brine Pond liner replacement and salt/sand disposal

TBD	TBD	2019.SMT.Jal. Inline filters for line coming in from MAPCO

TBD	TBD	2019.SMT.Jal NGL Storage Facility. Install a gas separator in the brine line

TBD	TBD	2019.SMT.Jal NGL Storage Facility. SDV upstream of product pumps & relocate discharge/suction valves outside of pump room

For any such projects listed above in this section 7 that are required to maintain safe operation and compliance of the Assets, the Partnership shall determine the final project scope in its sole discretion.

Expense and/or Capital Projects

The Parties agree that the following tanks relating to the LARW Refinery Unit included in the 2018 Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within

Schedule VI- Page 26 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

the 36 months prior to the date hereof, or are deemed in compliance with API 653 through current risk-based management inspection (RBMI) standards and whose next API 653 inspection is scheduled greater than 20 years after the Effective Date, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of Andeavor.


Tank Number
776
777
778
779
780
1503
13502
50000
80035
80057
80092
80219
125001
125002

The Parties agree that the following tanks relating to the LARC Refinery Unit included in the 2018 Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 36 months prior to the date hereof, or are deemed in compliance with API 653 through current risk-based management inspection (RBMI) standards and whose next API 653 inspection is scheduled greater than 20 years after the Effective Date, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of Andeavor.


Tank Number
74
350
351
352
353
354
355
681

Upon mutual consent on project scope between the Andeavor Entities and the Partnership, the Andeavor Entities shall reimburse the Partnership Group for all expense and capital costs incurred for the execution of the following miscellaneous projects at the LARW Refinery Unit or LARC Refinery Unit, identified in the table below.

Schedule VI- Page 27 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


NRE ID#		Description

6473		RP&S Replace 200 ft of 8” Slops Line

6456		RP&S Replace 800 ft of 12” Vapor Recovery Piping—V2331 to VXXXX

6474		Tank 80219, hot tap a new nozzle at ~15’

6477		REPLACE LIGHTING AT CONTROL ROOM MANIFOLD

6273		Brinewater to slop Bypass line

6280		PLATFORM BETWEEN TANK 80219 AND 80087

6197		RP&S Install minimum flow kickback forP-1206

6202		RP&S Steam pressure control valve at tank 118066

5802		Replace73-CP-1 (RP&S Central Tank Farm) PLC

TBD		Clean and air gap tanks 11000, 11001, 11003 and 11004

The Parties agree that the following tanks relating to the Mandan Refinery included in the 2018 Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 36 months prior to the date hereof, or are deemed in compliance with API 653 through current risk-based management inspection (RBMI) standards and whose next API 653 inspection is scheduled greater than 20 years after the Effective Date, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of Andeavor.

Tank Number

FB-702

FB-708

FB-714

FB-715

FB-721

FB-722

FB-725

FB-726

FB-728

FB-729

FB-731

FB-744

FB-747

FB-753

FB-758

FB-771

FB-774

Upon mutual consent on project scope between Andeavor and the Partnership, the Andeavor Entities shall reimburse the Partnership Group for all expense and capital costs incurred for the execution of the following miscellaneous projects at the Mandan Refinery, identified in the table below.

Schedule VI- Page 28 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Expense Order #		Description

9005833		OTE—GA759 & GA759S Pump Foundation Replacement

9026500		OTE—Remove OM RV Pot & Modify Drain Piping

unknown		OTE—Resolve Wet Propane Issue

The Parties agree that the following tanks relating to the Salt Lake Refinery included in the 2018 Assets Contribution Agreement listed on Schedule VII have been inspected, cleaned, and repaired to ensure compliance with API 653 or API 510 standards within the 36 months prior to the date hereof, or are deemed in compliance with API 653 through current risk-based management inspection (RBMI) standards and whose next API 653 inspection is scheduled greater than 20 years after the Effective Date, and are excluded from the reimbursement requirements listed above unless such actions fail to meet such compliance standards due to the negligence of Andeavor.


Tank Number
142
190
204
212
213
244
306
321
326
330
427C

Upon mutual consent on project scope between Andeavor and the Partnership, the Andeavor Entities shall reimburse the Partnership Group for all expense and capital costs incurred for the execution of the following project at the Salt Lake Refinery, identified in the table below.


IDEA#		Description
Unknown		Tank 297 – Lift and Level

Schedule VI- Page 29 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Asphalt Terminals


Description		Location
Berm repair		Elk Grove

Expense and/or Capital Reimbursements Identified in Due Diligence

Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of the Partnership Group, the applicable Andeavor Entities shall reimburse the Partnership Group for all expense and capital costs incurred for the execution of the following Andeavor reimbursements identified in the tables below. For all reimbursements in which a study, evaluation, inspection or review must first be performed, such activity must be conducted within 24 months of the Effective Date in order to be subject to Andeavor reimbursement.

Los Angeles Refinery Carson


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

LAR	The recently revised CA OSHA Rule 5189.1, Process Safety Management for Petroleum Refineries, incorporates a number of significant changes related to hazard reviews that will potentially result in modifications to RP&S assets. New review methodologies to be incorporated include: • Safeguard Protection Analysis • Hierarchy of Hazard Controls Analysis (HHC) • Damage Mechanism Reviews (DMR) Discussions with PSM staff indicated that while many of the practices have been adopted within the refinery, some of the additional hazard reviews are likely to result in project costs related to safeguard improvements	All costs related to implementing additional safeguard improvements to conform with changes in PSM requirements

LAR	Underground piping is removed/decommissioned as part of the UPR effort ongoing at the refinery (required by Cleanup Abatement Order (CAO)). There is a risk that additional underground piping not previously identified will need to be included in the program. Between 2003 and December 2017, approximately 89,895 feet of aboveground pipeline were installed and approximately 69,182 feet of underground pipeline were decommissioned.	All costs for projects to comply with Cleanup Abatement Order, decommissioning underground piping not previously included in the removal program

Schedule VI- Page 30 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

LAR	Additional investment related to Air Toxics health risk reduction requirements may be required due to: • Increased calculated health risk due to changes in California Air Toxics risk calculation methodologies, resulting in additional risk reduction activities • Increased focus on risk from refineries due to California AB617 community monitoring that could lead to additional emission control requirements on tanks (adding domes or vapor recovery to additional tanks), alternative measures for providing power during turnarounds (eliminating portable engine use), and additional cost related to controlling vacuum truck emissions. • Increased cost related to SCAQMD Rule 1180 Refinery Fenceline and Community Air Monitoring (additional instrumentation will be installed in the next year and may need to be updated in 5 years)	All costs related to identified projects required to comply with California Air Toxics regulations

LAR Carson	Shared containment dikes without intermediate subdivisions (773, 774, 775). Potential risk of fire spread between tanks.	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

LAR Carson	Tanks 677, 678, 679, 680 (15k bbl. each) are out of service. Tanks would require extensive repairs to reinstate, including adding anchors for seismic stability due to height to diameter ratio.	All costs to perform study to determine if tanks should be demolished and for any resulting costs to demolish tanks, if required.

LAR Carson	Vessels grouped into shared containment areas without subdivision or remote impoundments (pentane spheres 681, 682, 683, 684) and (propane bullets 350, 351, 352, 353, 354, 355)	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

LAR Carson	There is an ongoing, but incomplete project to upgrade the tank L&J Technologies gauging system to radar type.	All costs to upgrade the tank L&J Technologies gauging system to radar type.

LAR Carson	Motorola Intrac tank overfill protection system is no longer supported. A project has been identified to upgrade it.	All costs to upgrade tank gauging and control systems

LAR Carson	Arc flash labels are not provided on any equipment. There is a program in place to correct this within the next two years. Part of the energized work permitting process is have the facility engineer use the existing ETAP model to calculate the incident energy at the work location.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

LAR Carson	Two single bottom tanks do not have adequate levels of cathodic protection.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

LAR Carson	Cathodic protection levels on the buried facility piping could not be verified due to suspect data.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

Schedule VI- Page 31 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2. Los Angeles Refinery Wilmington


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

LAR Wilmington	LPG vessels 6000 and 6001 as well as the 700 series LPG vessels (7 total) do not have a back-flow check valve or thermal activated automatic shutdown valve in place as required per NFPA 58.	All costs for upgrades required to comply with NFPA 58 automatic shutdown requirements on tanks 6000 and 6001 and 700 series tanks

LAR Wilmington	Pressure relief devices onV-1700 series pressure vessels (gasoline) vent to atmosphere directly above vessel.	All costs to evaluate requirements and for any related projects required to rerouteV-1700 series pressure vessels relief vents

LAR Wilmington	No cable type ground connection between the rack and rail car was observed.	All costs to evaluate grounding requirements at the LPG train car rack and for any related projects required to meet Andeavor standards

LAR Wilmington	The loading safety platforms need upgraded.	All costs to upgrade rail car loading racks to Andeavor Logistics standards

LAR Wilmington	The truck rack lacks a grounding assurance system.	All costs to install interlocks and grounding systems on Truck & Rail racks

LAR Wilmington	Arc flash labeling is incomplete.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

LAR Wilmington	The Honeywell DCS system for both the inline blending area and tank farm is no longer supported. A project has been identified to upgrade to the E300 system.	All costs related to any control system upgrades needed for the Honeywell inline blender

LAR Wilmington	The first phases of the project to upgrade tank gauging to radar type used a wireless system to report data to the control system. Current Andeavor practice is hard wire level transmitters. An evaluation of the security of the wireless system is being conducted.	All costs related to modifying wireless systems to hardwire to meet Andeavor standards.

LAR Wilmington	There is an ongoing, but incomplete project to upgrade the tank gauging system to radar type. Approximately 30 tanks still need to be completed.	All costs to upgrade tank gauging to radar types

LAR Wilmington	No operational cathodic protection exists to protect aboveground storage tanks with single bottom floors or buried facility piping in direct soil contact.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

LAR Wilmington	No fixed fire protection on tanks 13506, 13507, 13508, 7200.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Schedule VI- Page 32 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

LAR Wilmington	The following observations were made related to secondary containment at LARW that will require additional investment: • Erosion of roads and berms was observed (not only asphaltic covering, but the underlying soil starting to show shear, erosion, signs of scouring). • Integrity of sidewalls, cracks observed in concrete around west side tanks (north wall). • Weak and uncoated points in berms. • Tank dike floor has been excavated to below the berm wall substrate in South tank farm, which may compromise the berm integrity. • Piping interconnections between berms should be reviewed as part of the SPCC Plan renewal efforts.	All costs to complete SPCC plan review and to make any necessary repairs to improve tank farm berms and roadways atLAR-Wilmington
LAR Wilmington	LPG Rail and Truck loading racks lack the following safe guards: • No driver card system, • Loading operation is manual, • No predetermined load volume capacity, • No automated gauge/level monitoring, • functional fire detection UV/IR with automatic water deluge (system is installed, but has not been commissioned).	All costs for initial review of safe guards and for any resulting improvements required to bring the LPG rail and truck rack up to Andeavor standards
LAR Wilmington	Four clusters of four 80,000 bbl. tanks containing crude, slop, transmix or VGO have comingled secondary containment dikes. An event of loss of primary containment (LOPC) in one tank would spread to the entire surface of the common dike floor, creating a large spill area. If the event is ignited (pool fire) the consequence would be more severe and lead to potential escalation to neighboring tanks. Construction of additional segregation berms would be required for tank segregation containment.	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

LAR Wilmington	Butane spheres and propane bullets near to the road tanker loading/unloading area are not equipped with flammable or fire detection.	All costs to evaluate fire protection systems to ensure compliance with NFPA, local city regulations and Andeavor fire protection standards; and for any resulting modifications required to comply with above regulations and standards

3. Mandan Refinery


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Mandan	Multiple tanks grouped into a single secondary containment dike lack subdivision berms resulting in potential spread of spills to inundate all tanks in the group. This increases the risk of loss in the event of a fire. Reference tank groups (743, 745); (737, 738); (741, 756, 707, 709); (715, 714, 710, 708, 712, 711); (742, 744, 720, 718); (719, 722, 721, 732, 756); (757, 716); (717, 740)	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

Schedule VI- Page 33 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Mandan	Three significant dents are present at the top course of the north face of Tank 734.	All costs to evaluate integrity of tank 734 dents and to make any required repairs

Mandan	U-1A forms are not available for all pressure vessels (bullets and spheres). Modifications, if required, may become complicated without the original manufacture forms.	All costs to perform a refinery engineering review and to document originalU-1A forms are on file for all pressure vessels, and all costs to replace any vessels, if required

Mandan	Original drawings indicate shells of the LPG bullets are made of ASTM A212 steel, which historically has had failures associated with brittle fracture. The material is no longer made. Mandan has a DMT of about-20F, so brittle fracture should be considered in vessel materials.	All costs to perform a study, if needed, to evaluate brittle fracture areas on LPG bullet tanks, and to cover any resulting repairs required

Mandan	A majority of the concrete pipe support foundations have experienced heaving/settling, in some cases failing completely, resulting in loss of support of the pipe. Many foundations are cracked, eroded, or completely broken away exposing the reinforcing steel and are no longer providing support to the piping.	All costs to perform a study to evaluate tank farm pipe foundations and supports in question and any costs to address deficiencies discovered

Mandan	Several supports for the 14” jet fuel pipe routed along the west side of Tank 734 have failed completely. The pipe is spanning approximately80’-0” unsupported which could result in overstress.	All costs to repair supports on the 14” jet piping along the west side ofTK-734

Mandan	The LPG transfer pump 759 and 759S foundation and support slabs are compromised and do not provide sound support or drip containment for the pumps. Refinery stated the pump foundations are slated for replacement.	All costs for projects to repair or replace LPG pump 759 and 759S foundations

Mandan	Pump 778 has issues with its dry well collecting liquids which can freeze and cause misalignment of the pump. Other pumps in the area (e.g. 759) do not have the same capacity as 778, so when pump 778 goes down flow to the process is limited. Refinery personnel indicated a project to relocate pump 778 is in initial stages to determine funding.	All costs to conduct a complete mechanical reliability evaluation of pump 778 and to upgrade and or relocate, as needed

Mandan	No document control for P&ID updates or revisions. Work history on pumps is only available for the past year due to the new system for tracking pump maintenance.	All costs to evaluate document controls and determine if appropriate P&ID’s, plot plans, isometric and electricalone-line drawings and maintenance records are in place, as well as to prepare any required documents.

Mandan	The rail car loading stations on track 8 have catch basins for spill collection. The catch basins are piped to a sump with integrity of buried pipe unknown.	All costs of recommended underground piping replacements, as a result of initial catch basin inspections. Inspections are being implemented into refinery inspection programs for rail car loading stations.

Mandan	Cable tray and conduit has failed at many locations due to being exposed to snow loads, or due to settling/heaving or failure of pipe supports. Failed conduit may be located in classified areas, with internal wiring exposed.	All costs to perform a survey of the tank farm and identify any failed trays and conduits and implement projects to repair.

Schedule VI- Page 34 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Mandan	Fire and Gas detection is typical of this type of facility and consists of direct observation by field personnel.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Mandan	35 storage tanks do not have fixed fire protection systems for delivery of foam to the tank interior.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Mandan	Fire foam piping within the tank farm is poorly supported due to support failure. Supports have jacked or settled and, in several locations, are no longer supporting the piping.	All costs to conduct a survey of the tank farm, to determine if there are failed fire foam piping supports, and for any resulting projects required to make repairs

Mandan	Storage tank level monitoring varies throughout tank farm. Some tanks do not have independent high-level switches. Some tanks do not have levels that report to the control room—level is monitored at the tank using the gauge board. Lack of high level switches increases potential for overfill.	All costs to conduct a survey of the Andeavor requirement for high level switches, and for any resulting projects to address deficiencies

Mandan	No lightning protection system was observed on storage tanks with EFRs.	All costs to evaluate requirements for lightning protection on storage tanks and to address any deficiencies to Andeavor standards

Mandan	Cathodic protection of the buried product facility piping could not be verified as CP monitoring is not being performed on an annual basis.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

Mandan	Cathodic protection of the tank bottoms could not be verified as perimeter readings are being obtained and the data is suspect.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

Mandan	Tracks have significant settlement at decanted oil, diesel and jet, and LPG transfer areas.	All costs forone-time 3rd party rail integrity assessment and any repair recommendations identified

Mandan	Rail electrical isolation between mainline and spurs to decanted oil, diesel and jet, and LPG transfer areas appears to be compromised.	All costs forone-time 3rd party rail integrity assessment and any repair recommendations identified

Mandan	Foundations have settled or heaved creating unleveled walking surfaces and tall bottom steps to grade creating fall hazards.	All costs to conduct a survey of stairways not in compliance with OSHA requirements and those with uneven walking surfaces and for any resulting projects required to address safety concerns

Schedule VI- Page 35 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Mandan	Access ladders at the aboveground storage tanks exceed OSHA height limits without intermediate landings and do not include safety cages or fall protection devices.	All costs to conduct a survey of tank access ladders for compliance with OSHA and for any resulting repairs required to address deficiencies

Mandan	The SPCC Plan does not document the volumes of the secondary containment calculations. The numbers presented in the plans are the design basis for the containments.	All costs to perform SPCC Plan update and for any resulting secondary containment improvements required

Mandan	RSR compliance modifications are excluded from tank inspection plan. Three tanks have been identified that will require equipment upgrades for compliance with the Refinery Sector Rules (RSR) provisions for tank seal and gaskets. The Refinery cost estimates have been identified for the three tanks. Future inspections are expected to identify similar missing seals on smaller openings and equipment modifications related to RSR compliance have not yet been determined for 7 other tanks.	All costs to complete inspections for tanks subject to refinery sector rules and for any resulting modifications or repairs required to address deficiencies related to RSR compliance

Mandan	Ethanol tank (Tank 758) will need IFR or vapor control. Tank just moved into Group 1 and is now in Refinery Sector Rule (RSR).	All costs to install IFR or similar vapor controls on Ethanol tank 758, required to ensure compliance with Refinery Sector Rule

Mandan	The rack drip pans and rail loading area drain to a sump. Based on discussions with Operations and Environmental, it was unclear who inspects/monitors the sump and if the sump is currently operational because it was disconnected from the truck rack. The sump is not equipped with an automated pump or alarm. The concrete sump appears to be in poor condition with spalling and cracks present, an indication of integrity concerns. A hydrocarbon sheen was observed on the water in the sump and the ground adjacent to the sump.	All costs to perform a study, evaluating integrity of the sump and its function in the context of SPCC plan

Mandan	Horse trough sump collects steam condensate and reciprocating pump compressor oil from LPG truck rack and LPG and butane storage tanks. A hydrocarbon sheen was observed on the water in the sump and on the ground adjacent to sump, indicative of an overfill of the sump.Sump is not equipped with automatic alarms or shutoffs to prevent overflow. Sump is maintained by operator of the LPG truck rack who calls a vacuum truck to empty sump.	All costs to perform a study, evaluating integrity of the sump and its function in the context of SPCC plan

Mandan	Tanks in the tank farm did not have automated level indication. The facility is currently in the execute stage of the tank field modernization project that will see each tank receive automated level indication (MOCM20181397-001).	All costs related to installation of independent High level switches on tanks, as part of tank modernization project

4. Salt Lake Refinery


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Salt Lake	Tanks sharing a dike cell lack intermediate berms and do not provide 100% separation with the other tanks in such that they could inundate the adjacent tank if a spill occurred. A spill fire would be contained within the main diked area.	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

Schedule VI- Page 36 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Salt Lake	Many dike walls contain open culverts for communication between containment cells, or unsealed casings between cells. As a result, containment dike walls do not provide 100% separation with the other tanks in such that they could inundate the adjacent tank if a spill occurred. A spill fire would be contained within the main diked area.	All costs to conduct fire risk study, to determine risks associated with shared containment dikes, and for any related projects required to address NFPA deficiencies

Salt Lake	Tank 325 was modified with 6 vertical channel stiffeners at the north side of the tank to maintain the shape of the tank due to a reported fire in 1989. Refinery staff indicated issues with the floating roof snagging on the shell.	All costs to conduct an inspection of tank 325 and to address repairs through refinery tank repair program

Salt Lake	The shell at the bottom two courses of Tank 322 appears to be bulging, and the inspections group has been notified.	All costs to conduct an inspection of tank 322 and to address repairs through refinery tank repair program

Salt Lake	Dents or shell wall distortion is present at the 3rd and 4th course at the east side of tank 297, and at the base course of tank 308.	All costs to conduct inspections of tanks 297 and 308 and to address repairs through refinery tank repair program

Salt Lake	Riveted tanks are notes as weeping, resulting in staining on the ground.	All costs to conduct inspections of applicable riveted tanks and to address repairs through refinery tank repair program

Salt Lake	Tank 204 containment area has hydrocarbon product seeping from underground around the perimeter of the tank with oil staining at the gravel directly beneath the tank chime and throughout the containment dike areas.	All costs for managing Tank 204 asphalt contamination remediation and clean up, including any required tank inspections or related repairs or modifications

Salt Lake	Floating oil at surface water present at tank 247 due to storm water backup to oily waste system during rain event.	All costs to clean up tank 247 containment due to stormwater backups

Salt Lake	Out of service and dead leg piping in the tank farm is not actively managed.	All costs to conduct a study to identify out of service and dead leg piping in the tank farm and for any projects required to address recommendations per Andeavor standards

Salt Lake	Some grounding operations at loading/unloading racks do not have ground proving (Scully) systems in place.	All costs to conduct an evaluation of the potential need for ground proving interlocks on truck racks and for any resulting upgrades required per Andeavor Standards

Salt Lake	The butane loading rack building’s concrete column and roof girders are heavily spalled with exposed reinforcing steel throughout.	All costs to conduct an evaluation of the butane loading rack building concrete columns and roof girders, and for any projects required to address resulting recommendations

Schedule VI- Page 37 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Salt Lake	No automated fire or gas detection systems were observed; however this is typical for this type of facility.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Salt Lake	27 storage tanks do not have fixed fire protection systems for delivery of foam to the tank interior.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Salt Lake	The fire foam piping at 5 of the tanks with fire foam chambers extend down the shell with a flanged connection near grade. The fire foam piping does not extend to the edge of the containment dike. In the event of a fire, fire department would not have access to the foam piping connection without entering the dike and bolting up a flange. Connection to the existing flanged connection at the tank shell is unlikely to occur in the event of a fire event.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Salt Lake	The software controlling the gasoline blender pumps is outdated and no longer supported.	All costs related to upgrading the automation controls at the blender per Andeavor standards

Salt Lake	Storage tank level high-high level switches are not independently hardwired back to the DCS.	All costs related to installing High-High level switches to comply with NFPA 30 Chapter 21.7.1.1 and Andeavor standards

Salt Lake	Tank level alarms set higher than currently recommended by API 2350 resulting in recent overfill of one of the vessels.	All costs to conduct an alarm rationalization study on tank level alarm settings and to make required revisions in control systems per Andeavor standards

Salt Lake	Cathodic protection levels could not be verified for select aboveground storage tank bottoms and the buried facility piping.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

Salt Lake	Asphalt seeps were observed within the bermed area at Tank 204. The seeps cover areas around Tank 204 and can impact operations within the containment area.	All costs for managing Tank 204 asphalt contamination remediation and clean up, including any required tank inspections or related repairs or modifications

Salt Lake	The following issues with secondary containment and stormwater/wastewater management were identified at the Site: 1) a survey of secondary containment volumes was completed during 2018 to confirm adequacy with respect to SPCC requirements; the report identified that Tanks 244 and 245 have inadequate secondary containment capacity and redesign is anticipated by the environmental representative. 2) The manual drain valve for the secondary containment berm around Tank 157 was reported by site personnel to be maintained open to allow general stormwater drainage from the depressed(low-area), exterior roadway to drain water from the road into the bermed area for storage/evaporation in an effort to reduce flooding; however, this is contrary to SPCC requirements.	All costs related to addressing improvements to SPCC plan containment and stormwater related deficiencies, as well as all costs related to wastewater cleanup

Schedule VI- Page 38 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement
	3) Free phase oil mixed with water was observed within the secondary containment berm for Tank 247. The site representative reported that the wastewater treatment facility capacity can be overwhelmed following heavy precipitation events, as occurred the day before the site visit. The backup of hydrocarbon containing wastewater into the tank berms reduces the secondary containment capacity and could result (temporarily) in noncompliance with the SPCC requirements as well as additional H&S and remediation activities.

Salt Lake	Site is in the process of completing a Baker Risk facility siting evaluation. Based on visual evidence and interviews with site personnel, major equipment relocation costs are anticipated.	All costs for repairs or projects to address risk reduction recommendations from Baker Risk Siting evaluation

Salt Lake	Eleven tanks have been identified that will require equipment upgrades in 2025 for compliance with the Refinery Sector Rules (RSR) provisions for tank seal and fitting vapor controls. The Refinery cost estimates are presented in the plant Ten Year Tank and Boiler Plan 2017.	All costs for tank seal and fitting vapor controls projects required for compliance with Refinery Sector Rules

Salt Lake	The RSR rule requires venting to be controlled during equipment maintenance. The Site has not yet identified the extent of equipment and maintenance shutdown venting that may be subject to the emission control measures required by the rule.	All costs for venting and emission controls projects required for compliance with Refinery Sector Rules

Salt Lake	The OMD (Oil Movements Division) PHA included the tank farm and remote tank farm. This PHA is currently in draft and under Site review. The PSM coordinator specifically indicated two recommendations will need to be corrected and are likely to be material: (1) A corrosion study needs to be completed and recommendations implemented. (2) More than 20 deadlegs were identified that potentially would need to be removed from service throughout the tank farm.	All costs to finalize PHA study and obtain related recommendations and then to address findings

Salt Lake	Three railcar derailments have occurred at the Site in the last 8 months, with one major derailment that required third party intervention to upright the cars. Facility representatives stated that one derailment was caused by ice and the other two derailments were caused by a rail integrity issue. The portion of the rail that was causing the issue was not identified during routine rail inspections. Representatives reported that the root cause of the rail integrity issue has not been identified. This rail section has since been replaced. Without understanding the integrity issue failure, the Site is not able to proactive address other sections of rail that may have similar integrity issues.	All costs forone-time 3rd party rail integrity assessment and any repair recommendations identified

Schedule VI- Page 39 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Salt Lake	No hydrocarbon detection and alarm systems exist in the LPG truck loading area that could notify operations of a continuous release. An LPG release in close proximity to loading trucks accessing the rack could result in a high consequence event.	All costs to evaluate the potential need to install hydrocarbon detection and alarms at the LPG truck loading rack and to ensure compliance with NFPA and Andeavor Fire Standards, and then to address any deficiencies discovered

Salt Lake	There are >20 tanks that will require foam injection capabilities to be added to meet Andeavor standards requirements.	All costs to conduct a study of fire protection systems and identify tanks needing modification to comply with NFPA or Andeavor fire protection standards, and then to address any deficiencies discovered

Salt Lake	A 2011 Hydraulic Model Study identified the blending facility lacks potential firefighting infrastructure.	All costs for upgrading the firefighting infrastructure at the blending facility per Andeavor standards

Salt Lake	Five pressure relief devices (PRD) within the tank farm are anticipated to be subject to the RSR PRD standards. The Site has not yet completed the regulatory evaluation and the final applicability determination. PRD monitoring systems are required for systems to be in compliance with the rule.	All costs to conduct a regulatory evaluation to determine if PRD monitoring systems are required to comply with Refinery Sector Rules, and then to address any deficiencies identified

5. Bakken Link and Fryburg


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

BakkenLink	The Arc Flash labels do not meet the requirements of the 2014 NEC (130D). The existing labels display the fault current but not the PPE requirements or the safe work zone.A 2018 project is in progress to complete an Arc Flash Study.	All costs related project to install Arc Flash labels

BakkenLink	Some CP test point locations do not exhibit adequate levels of cathodic protection.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys.

BakkenLink	The Arc Flash labels do not meet the requirements of the 2014 NEC. The existing labels display the fault current but not the PPE requirements or the safe work zone.A 2018 project is in progress to complete an Arc Flash Study.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

BakkenLink	The Arc Flash labels do not meet the requirements of the 2014 NEC. The existing labels display the fault current but not the PPE requirements or the safe work zone.A 2018 project is in progress to complete an Arc Flash Study.	All costs related project to install Arc Flash labels

BakkenLink	The aboveground storage tank shells were not grounded for lightning protection per NFPA requirements with the exception of the tanks at the Fryburg Rail Terminal.	All costs related to evaluate requirements for grounding tank shells for lightning protection per NFPA requirements and for any resulting repairs or projects required for NFPA compliance

Schedule VI- Page 40 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

BakkenLink	Several test points on the buried facility piping and tank bottoms do not exhibit adequate levels of cathodic protection.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

Dry Creek	An engineered drainage swale is present on the south side of the facility. Facility receives runoff from the eastern adjacent property that bypasses the engineered drainage swale and has eroded a swale along the northern boundary of the facility.	All costs related to conducting a study for diversion of offsite runoff away from the facility to eliminate erosion on the property and any resulting projects required

Fryburg	Sedimentation into and erosion of the tank berms has diminished the design containment capacity and sufficient freeboard. Due to the presence of excessive sediment and standing water within the tank farm secondary containment, there is a reduction in containment volume.	All costs related to conducting a study of existing containment capacity to ensure that sufficient containment exists (ensuring that the study includes accumulated precipitation and sedimentation in the containment calculations) and costs to correct resulting noted deficiencies

Fryburg	There is inadequate secondary containment for 110% of the largest vessel (a rail car) spill at the diesel car rail loading area.	All costs related to conducting and documenting a secondary containment impracticability study

6. Clearbrook Tankage, Minnesota Pipeline and Aranco Pipeline


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Clearbrook	Clearbrook—The transfer pipe between the primary and auxiliary roof drain sumps onTank-14 cracked during the winter of 2017 / 2018 resulting in contents of the tank accumulating on the floating roof. The issue has been temporarily addressed by facility operators and the tank construction contractor has been notified to perform warranty repairs. A member of the Partnership Group should verify repairs are made.	All costs to make any required repairs related to the transfer pipe between the primary and auxiliary roof drain sumps onTank-14.

Clearbrook	Clearbrook—The fire foam piping at Tanks 14 and 15 extend down the shell with a flanged connection near grade. The fire foam piping does not extend to the edge of the containment dike. In the event of a fire, the local volunteer fire department does not have access to the flanged connection from the access road. Connection to the existing flanged connection at the tank shell is unlikely to occur in the event of a fire event.	All costs to evaluate fire safety risk with 3rd party Operator and for resulting required project to route foam connections outside of the containment berm to a safe location.

Clearbrook	Clearbrook—Life of the semi-deep anode groundbeds could be reduced due to the absence of a venting system and use ofnon-chemically resistance anode lead cables.	All costs related to conducting a cathodic protection inspection and for any resulting repairs required.

Clearbrook	Tank 14 and 15 are designed to have foam for firefighting. The foam pipes end at the base of the tank so if there is a fire, firefighting crews will not be able to get close enough to the tanks to connect to the foam dispersal pipes.	All costs to evaluate fire safety risk with 3rd party Operator and for resulting required project to route foam connections outside of the containment berm to a safe location.

Schedule VI- Page 41 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Clearbrook	Tanks 14 and 15 are equipped with IFRs. The drain line between the secondary sump and the primary sump in Tank 14 leaked in the winter of 2017/2018. The leak discharged oil to the top of the IFR. The line between the secondary sump and the primary sump has been blinded in Tank 14 to eliminate a future recurrence of a release. Maintenance/repair of line will occur at next internal inspection. Repair costs will be material if undertaken outside of scheduled tank inspection.	All costs related to ensuring repairs are addressed in a timely manner and for any repairs required, which are not covered under tank warranty.

7. Conan Gathering System


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Conan	Pipe traps may not have proper dimension to support ILI tools. Oversize pipe segment (barrel) appears to be too short. Also, no flanges are provided to allow for extending the barrel length. # Receivers: 85 (assuming only receivers at CTB’s, TUL’s and Conan Terminal in scope) # Launchers: 79 (assuming only launchers at CTB’s and TUL’s in scope). It appears the launchers/receivers could be prepared for ILI using a replacement barrel and additional pipe spools (sharing of the replacement barrel and piping is dependent on diameter; system contains piping with diameter 6”, 8”, 10, 12” and 16”). Estimated cost for 10 extended barrels (launcher and receiver) and associated piping: $500k.	All costs related to correcting design issues with receivers and launchers.

Conan	Currently the leak detection system is mass balance system and is scheduled to be upgraded to ATMOS (quote was provided to project manager). Andeavor typically uses CPM through ATMOS. Total 91 Coriolis meters installed. Price to upgrade to ATMOS CPM is approx. $500k.	All costs to evaluate if ATMOS system is needed and for any resulting upgrade of the leak detection systems.

Conan	Fire Suppression—A modification to the tank fire protection system at Conan Terminal was ordered by EOG and is scheduled(Protect-O-Burn Self Expanding Foam System for rim seal protection on (3) tanks). Allocation of additional $1.2MM quoted cost for entire system is unknown.	All required costs to upgrade the fire system for rim seal protection on 3 tanks as ordered by EOG after determination of Andeavor Entity/Partnership Group allocation

Conan	Although the facilities are exempt from industrial stormwater permitting requirements by rule, it is not clear whether the design of the facilities is adequate to prevent discharges of contaminants that could otherwise trigger individual permit requirements. • Division berms and grading design may be insufficient to control drainage across the facilities (Hercules TUL in particular) and prevent stormwater from coming in contact with pollutants associated with process and truck unloading areas prior tooff-site discharge • Stormwater tanks associated with the truck unloading areas should be assessed for adequate capacity for the amount of received drainage Improved stormwater management/diversion practices are likely to be material.	All costs related to conduct an engineering design study for addressing containment of storm water within the property and for any resulting required projects to address deficiencies in storm water containment.

Schedule VI- Page 42 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

8. Rio Pipeline, Stateline and Midland Terminals


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Midland Terminals: Geneva/Zurich/Rio Pipeline	Rio Pipeline & Midland Short Haul Pipelines—CIS has not been performed to evaluate stray current interference from foreign operators.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys.

Midland Terminals: Geneva/Zurich/Rio Pipeline	Rio Pipeline – Rectifier #2 and #3 do not have AC power installed.	All costs related to projects required to install power to rectifiers #2 and #3

Midland Terminals: Geneva/Zurich/Rio Pipeline	Geneva—The intermediate tank containments did not provide 100% separation with the other tanks in such that they could inundate the adjacent tank if a spill occurred. A spill fire would be contained within the main diked area.	All costs related to conducting a fire risk study and to address any resulting deficiencies in compliance with NFPA codes, if required.

Midland Terminals: Geneva/Zurich/Rio Pipeline	Geneva & Zurich—Pipe supports do not allow for pipe flexibility and piping is likely overstressed on the longer pipe runs at the facilities.	All costs to conduct a study of the piping and for any resulting repairs required to address facility piping stresses

Midland Terminals: Geneva/Zurich/Rio Pipeline	Geneva & Zurich—Arc flash labeling is incomplete.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Midland Terminals: Geneva/Zurich/Rio Pipeline	Geneva & Zurich—The aboveground storage tank bottoms and facility piping do not exhibit adequate levels of cathodic protection at some test point locations.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys.

Midland Terminals: Geneva/Zurich/Rio Pipeline	Geneva & Zurich—The stair cross overs for piping and cable tray was not OSHA compliant. The tread depth was smaller than 10” and the height of the treads was over 7.5”.	All costs related to fix deficiencies on identified stairways not meeting OSHA compliance

Stateline Terminal	Pipe supports do not allow for pipe flexibility and piping is likely overstressed on the longer pipe runs at the facility.	All costs to conduct a study of the piping and for any resulting repairs required to address facility piping stresses

Stateline Terminal	The 10 truck lanes that are not metered and use the truck pumps to unload crude to tanksSL-1 &SL-2. The unloading trucks have no protection or warning if a downstream valve was closed. The truck pump will deadhead against the closed valve.	All costs related to installing overpressure or other protection controls on truck loading racks for tanksSL-2 &SL-2

Stateline Terminal	MCC Module panelboards and building disconnects lack Arc flash labels.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Stateline Terminal	Alarms and controls for truck offloading need to be reviewed. Power fluctuations are causing a flow control valve to close and divert product to the sump.	All costs related to upgrading electrical infrastructure at truck rack to prevent flow control valve closing and diverting product to sump

Schedule VI- Page 43 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Stateline Terminal	There are no control interlocks on ten of the truck loading lanes. Hoses and fittings can overpressure when flow control valves are closed as a result of site power fluctuations.	All costs related to installing truck rack overpressure control interlocks on truck loading lanes.

Stateline Terminal	Ten of the truck loading spots are not equipped with truck grounding indication or any interlocks with the offloading operation.	All costs related to installing ground proving interlocks and or grounding systems at loading racks

Stateline Terminal	The stair cross overs for piping and cable tray is not OSHA compliant. The tread depth was smaller than 10” and the height of the treads was over 7.5”.	All costs related to fix deficiencies on identified stairways not meeting OSHA compliance

Zurich, Geneva	The following issues with secondary containment were identified: • Theoff-loading is not equipped with secondary containment. • No design basis for secondary containment berm around Tanks (e.g., survey and geotechnical data on construction materials).	All costs related to conducting a containment survey and validating SPCC Plan and for any resulting projects required to address deficiencies found

Geneva	The following issues related to secondary containment were noted: • Facilityoff-loading lacks secondary containment. • No design basis for secondary containment berm around tanks (e.g., survey and geotechnical data on construction materials); • Blowing sand has filled part of secondary containment and berm erosion has occurred. • Additional concerns with containment capacity based on tank manifolding (three tanks are manifolded such that failure from one tank results in release from all three).	All costs related to conducting a containment survey and for any resulting projects required to address deficiencies found

Geneva	The following issues related to secondary containment were identified: • Inadequate secondary containment capacity for H2S scavenger stored in unloading area.	All costs related to conducting a containment survey and validating SPCC plan and for any resulting projects required to address deficiencies found

Stateline	Crude release (24.4 Bbls) occurred on March 8, 2018 due to power outage, which flowed across property andoff-site onto a neighboring. Remedial actions are in process. Additional information is required to ensure that the cleanup meets Texas cleanup requirements.	All costs related to indemnify for long term subsurface liability, if warranted, and to ensure remedial efforts meet the TCEQ Standards

Stateline	Lack of documentation indicating if retention pond has adequate capacity to prevent uncontrolled discharge from facility.	All costs related to conducting a study to determine capacity of stormwater retention pond and for making any resulting upgrades to ensure compliance with permits

Schedule VI- Page 44 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

9. Wink Station, Mason East Station, Yucca and Mesquite Truck Stations, Bobcat Pipeline


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Bobcat & Wink Short Haul Pipelines—The pipelines do not exhibit adequate levels of cathodic protection at multiple test point locations.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys.

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Bobcat & Wink Short Haul Pipelines—CIS has not been performed to evaluate stray current interference from foreign operators.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys.

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Consider appropriate measures for leak detection including CPM systems such as ATMOS or Telvent.	All costs to conduct a study to determine if additional leak detection measures are needed and for any resulting projects required to address leak detection deficiencies

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	MCC Module panel boards, vendor modules and skids, and cathodic protection equipment lack Arc flash labels.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Kinder Morgan and Plains sites lack arc flash labels.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Tank 3513—One test point location does not exhibit adequate levels of cathodic protection.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

Wink Station, Bobcat Pipeline, and Jack Rabbit Short Haul Pipelines	Jackrabbit Station—Cathodic protection levels of the buried facility piping could not be verified as CP monitoring is not being performed on an annual basis.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

Mason Station East	A study was conducted by Rooney Engineering after a flooding event occurred. Some upgrades were made based on the study, but similar rain events have not reoccurred yet to determine if the corrective measures were adequate. Further evaluation and additional upgrades could be required	All costs related to addressing any remaining Rooney Engineering recommendations deemed necessary for mitigation of facility flooding

Mason Station East	MCC Module, fire pump building, and warehouse building panel boards lack arc flash labels.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Mason Station East	The aboveground storage tanks do not exhibit adequate levels of cathodic protection at some test point locations.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

Mason Station East	Cathodic protection levels of the buried facility piping could not be verified as CP monitoring is not being performed on an annual basis.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

Schedule VI- Page 45 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

TexNewMexX: Yucca & Mesquite	Mesquite & Yucca – Some MCC Module panel boards and cathodic protection equipment lack arc flash labels.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

TexNewMexX: Yucca & Mesquite	Mesquite & Yucca – Cathodic protection levels of the buried facility piping could not be verified as CP monitoring is not being performed on an annual basis.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

10. Jal NGL Storage Facility


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement

Jal	Out-of-service fractionator equipment has been abandoned in place with heat exchanger heads open, vessel manways open, open-ended piping. There is no HazCom signage (i.e. regarding confined spaces, ACM, lead-based paint) and the volume/quantity of lead based paint and ACM has not been quantified.	All costs related to conduct study to determine if tanks should be demolished and associated costs to demolish tanks, if needed

Jal	The facility siting study required under PSM is not based on the current site layout.	All costs related to evaluation of facility siting based on current site layout and for any resulting modifications required

Jal NGL Storage Facility	A number of concrete piping supports are cracked or completely broken away exposing the rebar.	All costs related to repairing identified broken concrete pipe supports

Jal NGL Storage Facility	The rail access platform was constructed in the late 1950’s with the construction of the fractionation plant and currently would be unable to support the weight of a new safe rack gate system if future safety upgrades are required.	All costs to conduct a study of the rail access platform and for any resulting projects required to make safety improvements to meet Andeavor standards

Jal NGL Storage Facility	The LGP rail access platforms have no overheadtie-in safety system for the operators to use when accessing the top of the rail cars.	All costs related to projects to upgrade rail car racks loading platforms to ensure safe access to meet Andeavor standards

Jal NGL Storage Facility	Well-degasser needed for facility. A casing leak could lead to butane in water which settles into storage ponds for a large flashing to atmosphere scenario. If ignition source is found near pond this could lead to a vapor cloud explosion.	All costs related to evaluation of potential casing leak scenario and costs to implement recommended safe practices

Jal NGL Storage Facility	T-825 does not have aU-Stamp affixed to the vessel and will require replacement of the vessel.	All costs related to installation of a new vessel or to provide certification andU-stamp for T-825.

Jal NGL Storage Facility	Arc flash labeling is not provided on any of the electrical equipment.	All costs for installation of required Arc Flash labels, discovered through initial evaluation

Jal NGL Storage Facility	Area classification drawings are not available.	All costs to create and stamp facility electrical area classification drawings

Schedule VI- Page 46 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement
Jal NGL Storage Facility	Noon-site water or foam supply for fire protection. Fire protection is provided by volunteer fire department with limited resources for water supply.	All costs related to making required water or foam supply modifications to comply with Andeavor fire protection standards

Jal NGL Storage Facility	No fire or gas detection is provided. Operations is particularly concerned with the lack of fire and gas detection in the pumphouse.	All costs related to performing an evaluation to determine if additional fire or gas detection is needed and for installing fixed gas detection monitors and or ESD at the pumphouse as per Andeavor standards

Jal NGL Storage Facility	A SCADA control system is not installed. All controls and interlocks are directly hardwired, and remote monitoring is not provided for operators.	All costs for installation of remote monitoring or SCADA control systems to meet Andeavor standards

Jal NGL Storage Facility	Consideration should be given to performing a PHA and evaluating the need for additional ESD valves for the wells.	All costs related to conducting a PHA study and for any required projects to address deficiencies

Jal NGL Storage Facility	Tank 825 is not equipped with any pressure instrumentation, temperature instrumentation, or automated valves. Recommend evaluating the need for additional monitoring and protection for the tank.	All costs to perform automation study and for any resulting projects to install automation instrumentation for tank 825 to meet Andeavor standards

Jal NGL Storage Facility	The booster pump and Tank 825 are not equipped with bonding jumpers.	All costs to survey facility and identify any conduit fittings missing bonding jumpers and to address deficiencies

Jal NGL Storage Facility	Some liquid-tight fittings are not installed with bonding jumpers.	All costs to survey facility and identify any conduit fittings missing bonding jumpers and to address deficiencies

Jal NGL Storage Facility	Tank ground indication is not provided at the rail rack.	All costs related to installation of pump interlocks and ground proving (Scully) systems on rail rack to meet Andeavor standards

Jal NGL Storage Facility	Pump interlocks with the truck rack and rail rack grounding systems are not provided.	All costs to install pump interlocks and ground proving (Scully) systems on truck rack to meet Andeavor standards

Jal NGL Storage Facility	Two truck loading spots are not provided with ground indication.	All costs to install ground proving (Scully) systems on truck racks to meet Andeavor standards

Jal NGL Storage Facility	No active CP systems or monitoring program is in place for the buried facility piping. A foreign CP system is adjacent to the facility which could be cause stray current interference.	All costs related to addressing cathodic protection deficiencies after verification of cathodic protection surveys

Schedule VI- Page 47 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

11.

Wingate Terminal


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursement
Wingate	Secondary containment around four legacy sphere tanks has torn liner that is in need of repairs or replacement. Two spheres have containment without liners.	Once a study sphere use is complete, all costs related to conducting a study on secondary containment and for any resulting requirements to address deficiencies.

Wingate	Two artesian water wells (No. 3 and 4) have leaking casings at the tops of the well heads. The leaking water created a>1-acre wetland area that is permanently saturated. The costs tore-drill the wells would be material. A recent NMED inspection identified the need to repair the wells.	All costs for any mechanical integrity repairs to water wells No. 3 and 4 associated with recent inspection reports identifying need to redrill the water wells

Wingate Terminal	The rail access platform was constructed in the late 1950’s with the construction of the fractionation plant and currently would be unable to support the weight of a new safe rack gate system if future safety upgrades are required.	All costs to conduct a study of the rail access platform and for any resulting projects required to make safety improvements to meet Andeavor standards

Wingate Terminal	The concrete foundation under propane tank 518 has a significant crack that exposes the rebar inside the foundation and is a structural concern	All costs related to either repairing the foundation or removing the vessel

Wingate Terminal	No back-flow check valve or thermal activated automatic shutdown valve in place as required per NFPA 58.	All costs related to making upgrades to vessels to meet requirements of NFPA 58

Wingate Terminal	Seven vessels are overdue for inspection(V-400 throughV-406) and one vessel(V-407) is out of service.	All costs to inspect vessels prior to their returning to product service

Wingate Terminal	The concrete foundations for the horizontal iso butane tanks209-214 & propane tanks508-517 are showing signs of cracking.	All costs to evaluate foundation cracking on LNG tanks209-214 and508-517, to determine if repairs are required, and for any resulting required LNG tank foundation repairs

Wingate Terminal	Gas detection is not provided at the spheres. Consider evaluating the need for additional gas detection.	All costs to perform a study to determine if facility is in compliance with NFPA codes and for any related projects to comply with fire codes or Andeavor standards

Wingate Terminal	One sphere does not appear to have ground bonding jumpers.	All costs to correct ground bonding jumper deficiency on sphere

Wingate Terminal	The rail rack is not equipped with ground indication or process interlocks with a grounding system.	All costs to install ground proving (Scully) systems on truck racks

Wingate Terminal	Cathodic protection levels for the buried facility piping, pressure vessels bases, and water storage tanks could not be verified as CP monitoring is not being performed on an annual basis.	All costs related to conduct an initial cathodic protection survey and for addressing any cathodic protection deficiencies discovered

12.

Elk Grove Asphalt Terminal


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Elk Grove Terminal	An unsupported vent pipe span at the polymer modified asphalt blending area is experiencing excessive movement and deflection.	All costs to conduct an engineering review of unsupported piping spans at the polymer modified asphalt blending area and to address any deficiencies identified

Schedule VI- Page 48 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Elk Grove Terminal	Rail rack piping has no expansion loops for piping flexibility. Offload pumps are located at both ends of the rail rack which act as anchors and pump nozzles could be overstressed.	All costs to conduct an engineering review of unsupported piping spans at the rail rack and address any deficiencies identified

Elk Grove Terminal	The condensate return tank (adjacent to the hot oil heaters) is vibrating excessively.	All costs to conduct an engineering review of the condensate return tank, to determine root cause of excessive vibration, and to address any deficiencies identified

Elk Grove Terminal	The retractable landings do not provide fall protection on all sides.	All costs to Implement interim mitigations to reduce risk of falls to personnel and undertake projects to address tank fall protection concerns at the truck offloading stations.

Elk Grove Terminal	No fall protection is present for personnel accessing the tops of rail cars.	All costs to Implement interim mitigations to reduce risk of falls to personnel and undertake projects to address tank fall protection concerns at the rail car.

Elk Grove Terminal	Existing vapor collection piping is reportedly plugging regularly, and the system is not adequately functioning.	All costs to investigate root cause of plugging in the vapor collection piping and for any projects required to repair

Elk Grove Terminal	The vapor collection system piping is not finished.	All costs to evaluate and complete prior project for Phase 2 installation of vapor collection systems, if required

Elk Grove Terminal	Although the site is equipped with seven cameras, the image quality is poor, and they are frequentlynon-functional.	All costs to conduct a security assessment to ensure compliance with Andeavor security standards and to address any gaps through a security upgrade project and to update security cameras.

Elk Grove Terminal	Noarc-flash studies have been conducted and the electrical distribution equipment is not equipped witharc-flash warning labels.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

Elk Grove Terminal	Electrical drawings(One-Lines, Area Plans) and documentation are not available for the terminal. Limited project specific documents may be available.	All costs to determine if appropriate P&ID’s, plot plans, isometric and electricalone-line drawings and maintenance records are in place, as well as to prepare any required documents.

Schedule VI- Page 49 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Elk Grove Terminal	No automated fire or gas detection systems were observed; however, this is typical for this type of facility. Manual alarm pushbuttons are installed, but are not functional.	All costs related to performing an evaluation to determine if additional fire or gas detection is needed and for addressing any identified deficiencies in compliance with NFPA codes and Andeavor fire safety standards

Elk Grove Terminal	A control panel is available for the PMA and tank wetting systems, but no other SCADA controls are available at the terminal for remote monitoring or automated shutdowns.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Elk Grove Terminal	A control panel is available for the SAAB tank gauging, but it was only operational for a short period.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Elk Grove Terminal	The emulsion tanks are not equipped with either radar or site gauges.	All costs to conduct a study to evaluate need for SCADA or similar controls for the emulsion tanks and to implement findings as per Andeavor standards

Elk Grove Terminal	Asphalt tanks are equipped with Rosemount SAAB level radar gauges, but do not have Varec local site gauges forback-up. Reportedly, there is a project to install Varec gauges. The SAAB level radar gauges are not currently able to be remotely monitored.	All costs to conduct a study to evaluate need for SCADA or similar controls on the asphalt tanks and for installation of remote monitoring or SCADA control systems, Sabb Radar gauges, Varec local gauges and remote monitoring systems per Andeavor standards

Elk Grove Terminal	Cathodic protection systems do not exist to protect select aboveground storage tank bottoms and buried facility piping in direct soil contact.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Elk Grove Terminal	The Stairs/landings/walkways at the south end of the tank farm do not include a kick plate or center guardrail, and the guardrail members are not adequately sized to resist code applied live loads. The grating and support structure appears to be undersized since the grating surface is bouncy. In addition, piping running along the landings present a tripping hazard.	All coststo for projects required to address deficiencies with stairs, landings and walkways in the emulsion tank farm including kick plates and undersized gratings.

Elk Grove Terminal	The Stairs/landings/walkways at the Emulsion tank farm do not include a kick plate or center guardrail, and the guardrail members are not adequately sized to resist code applied live loads. The grating and support structure appears to be undersized since the grating surface is bouncy. In addition, piping running along the landings present a tripping hazard.	All costs to for projects required to address deficiencies with stairs, landings and walkways in the emulsion tank farm.

Elk Grove	The site has experienced numerous spills of asphalt. The spilled material was observed throughout the emulsion plant and the site. Thenon-recoverable asphalt storage area is full, and the site has begun a practice of placingnon-recoverable asphalt materials onto the soil near thenon-recoverable asphalt storage area.	All costs to perform initial clean up and disposal ofnon-recoverable asphalt as a result of historical spills across the site

Schedule VI- Page 50 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Elk Grove	Theon-sitepre-fabricated fire pump is not compliant with NFPA 20 and the 2016 California Fire Code. The following issues were identified: • The expose cables and battery constitute an electrical hazard; • The condition of the pump is not adequate—leaking oil is potentially providing an additional fire hazard; • The pump is feed by liquefied petroleum gas (LPG) which provides additional fire hazard, conditions of the electrical cables could lead to ignition. Are drive by diesel or electricity, LPG is not an acceptable medium to run a fire pump; and • Exhaust is release inside the room allowing for the accumulation of accumulating carbon monoxide.	All costs to conduct an inspection of the fire water pump, to determine if any potential areas ofnon- compliance with NFPA 20 and California Fire Code exist, and for any projects required to address deficiencies

Elk Grove	The following issues related to SPCC were identified. A26-inch wall surrounds the emulsion plant on three sides. The fourth side is the emulsion plant building; piping penetrations through the wall do not appear sealed, which reduces the actual containment volume. Additionally, ERM noted the following issues with containment at the asphalt plant: • Squirrels and burrowing owls are nesting in the containment walls, affecting berm integrity (the burrowing owl is a protected species). • Rainwater is pumped into the containment areas during times of heavy rainfall, limiting containment capacity.	All costs to evaluate SPCC issues identified and to address any deficiencies

Elk Grove	The site has experienced numerous asphalt spills. Most notable, in 2017, 125 tons of product from tank100-M2 was released due to a tank bottom failure. The majority of the spilled materials were removed Clean Harbors. The removal of spilled material was ceased to allow for the tank to be repaired. During warm weather, asphalt seeps are observed in the former spill area. In general, spilled asphalt materials were observed on the ground throughout the emulsion plant and the site. Thenon-recoverable asphalt jersey barriers is overfilled and the site has begun a practice of placingnon-recoverable asphalt materials onto the soil near the barriers.	All costs to perform initial clean up asphalt seeping from the area around Tank100-M2

Elk Grove	The site has installed a RTO, with some of the piping replaced with stainless steel. The remainder of the piping needs to be replaced to allow the RTO to properly operate. Estimated costs for this upgrade is $400K.	All costs to complete stainless steel piping replacement on RTO

13.

Mojave Asphalt Terminal


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Mojave Terminal	The listed API 650 name plate on tanksTK-1,TK-2,TK-3, andTK-4 state the maximum operating temperature at 180 Deg. F. The current operating temperatures of all four tanks are 350 Deg F. Documentation does not exist to support the current operating temperature which is beyond the stamped tank design.	All costs to conduct engineering reviews and management of change (MOC) reviews forTK-1,TK-2,TK-3, andTK-4, to verify the maximum allowable temperature of the asphalt tanks, and to make any required updates to tank nameplates and provide documentation of change

Schedule VI- Page 51 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Mojave Terminal	High level alarms for storage tanks do not exist. Tank gauging equipment and infrastructure are in place.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Mojave Terminal	Active below ground lines are present in facility (rail offload rack). No existing cathodic protection systems in place or inspection programs.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Mojave Terminal	The retractable landings do not provide fall protection on all sides.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at the truck offloading stations.

Mojave Terminal	No fall protection is present for personnel accessing the tops of rail cars.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns from the tops of rail cars.

Mojave Terminal	Existing thermal oxidizer system does not function correctly. May be undersized. Operations indicated it does not pull enough vacuum. Currently not being used.	All costs to conduct a review of the Thermal Oxidizer operational issues and for any upgrades required to improve operation if required to be in service.

Mojave Terminal	The terminal is not equipped with cameras or automated gates.	All costs to conduct a security assessment to ensure compliance with Andeavor security standards and to address any gaps through a security upgrade project

Mojave Terminal	Noarc-flash studies have been conducted and the electrical distribution equipment is not equipped witharc-flash warning labels.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

Mojave Terminal	Electrical drawings(One-Lines, Area Plans) and documentation are not available for the terminal. Project specific documents may be available.	All costs to determine if appropriate P&ID’s, plot plans, isometric and electricalone-line drawings and maintenance records are in place, as well as to prepare any required documents.

Mojave Terminal	A SCADA control system does not exist for the terminal.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Mojave Terminal	Cathodic protection monitoring is not being performed to evaluate the levels of cathodic protection on the aboveground storage tank bottoms and buried facility piping in direct soil contact.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Schedule VI- Page 52 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Mojave Terminal	An Andeavor Entity owned and DOT regulated out of service or abandoned underground pipeline segment is located on the terminal. Documents were not available for review to determine if the pipeline was properly abandoned or taken out of service. Reportedly the pipeline was pigged clean and purged with Nitrogen.	All costs to conduct a review of pipeline abandonment records and to conduct any corresponding additional inspections required to verify if pipeline was properly abandoned

Mojave Terminal	The tank containment dikes are not outfitted with stair styles for access over the berms or over some piping at the rail rack. Lack of stairs presents a slip/fall hazard.	All costs to Implement interim mitigations to reduce risk of falls to personnel and undertake projects to address tank fall protection concerns including installation of stairways at tank farm berms and rail car stations.

14.

Phoenix Asphalt Terminal


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Phoenix Terminal	Tank 4, 102 and 202 contain patch plates which do not appear to meet API 653 repair standards. No radius present at patch corners, and vertical welds are within 6” of each other.	All costs to inspect tanks for compliance with API 653 repair standards and to address any deficiencies with patch plates on tanks 4, 102 & 202

Phoenix Terminal	Some tanks share a common stair to access the tank roofs. Walkways, guardrails, ortie-off points for fall protection to access vent hoods, gage hatches, etc. are not present.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at stair access and tank roofs.

Phoenix Terminal	The retractable landings do not provide fall protection on all sides.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at truck loading racks.

Phoenix Terminal	No fall protection is present for personnel accessing the tops of rail cars.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns on tops of rail cars.

Phoenix Terminal	Noarc-flash studies have been conducted and the electrical distribution equipment is not equipped witharc-flash warning labels.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

Phoenix Terminal	Electrical drawings(One-Lines, Area Classification) and documentation are not available for the terminal. The area classification around the diesel and jet tanks and process piping should be reviewed and the suitability of the installed electrical equipment verified.	All costs to conduct a study to verify the suitability of installed electrical equipment around the diesel and jet tanks relative to area electrical classification standards and to create electricalone-line drawings and Area Classification drawings, if required

Schedule VI- Page 53 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Phoenix Terminal	A SCADA control system does not exist for the terminal.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Phoenix Terminal	Tanks are not equipped with any remote monitoring, alarms, or interlocks to prevent tank overfill.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Phoenix Terminal	Additional software is required to monitor the wireless Rosemount tank level transmitters from the main office.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Phoenix Terminal	Cathodic protection systems do not exist to protect select aboveground storage tank bottoms and buried facility piping in direct soil contact.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Phoenix Terminal	Stair rise/run at the stair style over the tank containment dike wall north of Tank 50001 varies, presenting a trip/fall hazard to personnel.	All costs to conduct a safety assessment of the stairs and to address any safety concerns identified at the stairway north oftk-550001

Phoenix	Underground vaults and drains are located at the site. Reportedly, the vaults discharge to the stormwater pond. However, piping was not observed at this discharge location. A piping drawing for underground lines does not exist according to site personnel. Facility personnel are unaware where the stormwater is discharging.	All costs to conduct a study to determine whether underground vaults are connected to the stormwater retention basin, to understand stormwater permitting requirements, and to address any deficiencies identified

Phoenix	According to the information provided, theon-site sewer may require cleaning due to blockage from calcium carbonate buildup and potentially need to be repaired or replaced. Previous estimates to replace the sewer line were approximately $250,000.	All costs to evaluate condition of underground sewer and to repair or replace, if required at the boiler area.

Phoenix	The site has installed a covered storage area for hazardous materials. The storage area is still in the process of being fully permitted and a sprinkler system is required by the local fire marshal. The site is actively using the storage area for hazardous materials storage.	All costs to install sprinkler system in the new storage building if required by building permit, local fire standards, or Andeavor hazardous materials storage management practices

15.

Bakersfield Asphalt Terminal


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Bakersfield Terminal	Some tanks share a common stair to access the roofs with no walkways, guardrails, ortie-off points for fall protection to access vent hoods, gage hatches, etc. In particular, operators must access tanks17-20 gauge hatches on a daily basis. Access to the gauge hatches requires operators to leave the rooftop walkway system and work near tank edges with no guardrails or fall protection present.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns from stair access and tops of tanks.

Schedule VI- Page 54 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Bakersfield Terminal	High level alarms for storage tanks do not exist. Tank gauging equipment and infrastructure are in place.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Bakersfield Terminal	Heat exchanger for asphalt product is not functioning properly and needs to be evaluated.	All costs to conduct an engineering study to determine if heat exchanger is operating per design and to address recommended upgrades if any are required

Bakersfield Terminal	Steam piping at rail rack shows signs of movement from thermal expansion. Additional shoes have been added to avoid pipe from dropping off support. Expansion loops should be considered in steam piping.	All costs to review piping at the rail rack to ensure there are adequate supports to prevent the piping from falling off the rack and to address deficiencies identified

Bakersfield Terminal	Active below ground lines are present in facility (rail offload rack). No existing cathodic protection systems in place or inspection programs.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Bakersfield Terminal	The retractable landing at emulsion rack 1 is heavily damaged with broken/bent rails. The landing is currently being used for accessing tops of trucks.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at emulsion tank 1.

Bakersfield Terminal	The retractable landings at lanes 1, 4 & 5 include a scaffold system for personnel fall protectiontie-off. The scaffold system does not appear to be adequately sized to support minimum OSHA load requirements, and is not inspected on a frequent basis by certified scaffold inspectors.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at truck rack lanes

Bakersfield Terminal	No fall protection is present for personnel accessing the tops of rail cars.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns from tops of rail cars.

Bakersfield Terminal	The vapor recovery and control system is inadequate to recover emissions from the asphalt tanks to prevent nuisance odor complaints from the community. Some tanks are not piped to the vapor recovery system.	All costs to conduct an engineering review of the vapor recovery piping and thermal oxidizer to ensure adequacy to capture all emissions from the tanks and to make any repairs needed

Bakersfield Terminal	Noarc-flash studies have been conducted and the electrical distribution equipment is not equipped witharc-flash warning labels.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

Schedule VI- Page 55 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Bakersfield Terminal	Electrical drawings(One-Lines, Area Plans) and documentation are not available for the terminal. Limited project specific documents may be available.	All costs to determine if appropriate P&ID’s, plot plans, isometric and electricalone-line drawings and maintenance records are in place, as well as to prepare any required documents.

Bakersfield Terminal	No automated fire or gas detection systems were observed, however this is typical for this type of facility.	All costs related to performing an evaluation to determine if additional fire or gas detection is needed and for addressing any identified deficiencies in compliance with NFPA codes and Andeavor fire safety standards

Bakersfield Terminal	A SCADA control system does not exist for the terminal.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Bakersfield Terminal	Tanks are not equipped with any remote monitoring, alarms, or interlocks to prevent tank overfill.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Bakersfield Terminal	Only one emulsion tank is equipped with a visual gauge. The asphalt tanks are only equipped with SAAB radar and no site gauges are available for comparison.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

Bakersfield Terminal	Cathodic protection systems do not exist to protect select aboveground storage tank bottoms and buried facility piping in direct soil contact.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Bakersfield Terminal	The guardrail of the stairs accessing the south side of truck loading lanes 4 & 5 is broken, presenting a fall hazard. In addition, no midrail is present at the stair and kick plate are missing.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns on lanes 4 & 5 guardrails, midrails and stairways.

Bakersfield Terminal	The corrugated metal pipe vaults at the below ground piping transitions inside the tank farm and at the rail rack are not covered and present a fall hazard to personnel.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall hazards associated with corrugated metal pipe vaults at the below ground piping transitions inside the tank farm and at the rail rack

Bakersfield Terminal	Access ladders at tankT-10 exceed OSHA height limits without intermediate landings and do not include safety cages or fall protection devices.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address OSHA height limits of Access ladders at tankT-10 including safety cages and fall protection devices.

Schedule VI- Page 56 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Bakersfield	An asbestos and lead survey was completed for the old lab and operations buildings. The survey indicated presence of asbestos as well as external green and white paints containing high lead contents. The external paint was observed in very poor and peeling conditions.	All costs to demolish existing buildings and replace with new, if required per Andeavor standards as result of reviewing findings from asbestos and lead survey

Bakersfield	A large quantity of super sacks is stored outside exposed to the sun. This material has been known to spontaneously ignite under high temp conditions. These materials need to be stored properly in sheds or covered storage areas.	All costs to identify safe storage requirements for all chemicals at the site and to address any safe storage deficiencies

Bakersfield	Site relies on a groundwater well for potable and process water. Reportedly, there is a well approximately 700 ft. deep (water level at about 500 ft.), with a submersible pump, installed around September 2013. There is a second well not in use and locked shut with the casing damaged (slots corroded, and sand has infiltrated the well). The site was unaware of any well abandonment, potable water testing or drinking water requirements.	All costs to test water on active well to verify it is potable, to connect facility to City water service if required, and to abandon water well per California Department of Water Resource regulations Health & Safety Code Section 115700, if required

Bakersfield	The following issues related to Air Permit compliance were observed: • The permit requires continuous use of a vapor control system (either carbon drums or thermal oxidizer) whenever tank contains or is being loaded with asphalt products. However, based on site observations the thermal oxidizer system is not in use and facility personnel reported the system wasnon-operational. • Facility has tendency to manually modify the design of the boilers in the event that it fails. This practice is not encouraged because it could lead tonon-compliance with permit conditions. • Rental loader was found on site. They need to be registered in the CARB system (DOORS) if used for longer than 1 year.	All costs to evaluate noted air permit compliance issues and to make necessary upgrades to the facility vapor recovery equipment based on permitting requirements

16.

All Asphalt Terminals


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
All Sites	Inadequate fall protection at the truck loading racks as well as other areas within the sites. It should be noted that the Fernley truck rack is equipped with cages.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns per Andeavor standards

All Sites	The sites lack a comprehensive fire safety program. Fire safety issues identified included: • No fire detection systems are in place and facility personnel rely on fire extinguishers for fire protection. • No active or adequate fire suppression systems are in place. • No response agreements are in place with local fire departments, nor do the facilities actively engage, or exercise, with emergency responders. • With the exception of Phoenix, fire hydrants fed by municipal water are not inspected on a regular basis. The facility representative indicated that inspections are conducted, but that documentation is not maintained regarding the inspections.	All costs related to performing an evaluation to determine if additional fire or gas detection is needed and for addressing any identified deficiencies in compliance with NFPA codes and Andeavor fire safety standards

Schedule VI- Page 57 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
	• Hazardous area classification assessments have not been conducted at the sites and numerous ignition sources are present. • Manual call points installedon-sites are disabled and not functioning. Therefore the call points will not activate any general alarm in the event of an emergency. No provisions have been implemented to fix the system.

All Sites	With limited exceptions, operations are performed manually, with no automation (e.g. MOVs, high level alarms, automated shut down devices, etc.). Overfill prevention is based on correct calculation of loading time based on the level before loading. The operator is required to perform level monitoring with manual gauges on top while loading is performed. Numerous tanks showed evidence of previous overfill events.	All costs to conduct a study to evaluate need for SCADA or similar controls and to implement findings as per Andeavor standards

All Sites	No arc flash studies have been performed at the sites.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

All Sites	According to information provided, over 90 tanks are past tank inspection due dates. With few exceptions, all tanks are single bottomed without means of detecting a tank bottom failure.	All costs to address overdue tank inspections as per API 653 and to address any deficiencies identified

All Sites	With the exception of Mojave, the following issues have been identified with respect to secondary containment with the exception of Mojave: • capacity of secondary containment areas appears inadequate at many locations • tanks were observed without secondary containment • secondary berms are eroding and do not have preventative maintenance programs • spill pans are not used during rail car unloading	All costs to conduct a review of SPCC plans and to address any deficiencies identified which are required to comply with SPCC requirements

All Sites	Boiler blow down at the sites is discharged to the ground or an impoundment. The sites are unaware of permitting requirements for this activity. Additionally, boiler blow down discharge on bare ground could lead to subsurface contamination.	All costs to review boiler blowdown permitting requirements, to obtain permits required to discharge boiler blowdown water to the stormwater pond if required, or to make other modifications needed for safe, compliant blowdown practices

17.Fernley Asphalt Terminal— Upon mutual consent on project scope between the applicable Andeavor Entities and the applicable members of Partnership Group, the applicable Andeavor Entities shall reimburse the Partnership Group for 50% [amount equal to Andeavor ownership at time of drop down closing] of the expense and capital costs incurred for the execution of the following Andeavor Reimbursements identified in the table below. For all reimbursements in which a study, evaluation, inspection or review must first be performed, such activity must be conducted within 24 months of the Effective Date in order to be subject to Andeavor reimbursement.

Schedule VI- Page 58 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Fernley Terminal	Some tanks share a common stair to access the tank roofs. Walkways, guardrails, ortie-off points for fall protection to access vent hoods, gage hatches, etc. are not present.	All costs to implement interim mitigations to reduce risk of falls and for any projects to address tank fall protection concerns from tank roofs and stair access points

Fernley Terminal	No fall protection is present for personnel accessing the tops of rail cars.	All costs to implement interim mitigations to reduce risk of falls and for any projects to address tank fall protection concerns from rail cars.

Fernley Terminal	Security cameras are not provided.	All costs to conduct a study/evaluation to determine security camera needs and for any projects to address identified deficiencies in Andeavor Security Standards

Fernley Terminal	The terminal entrance gate is not equipped with badge readers.	All costs to conduct security assessment and to address deficiencies relative to access gate badge readers as they relate to Andeavor security standards.

Fernley Terminal	Noarc-flash studies have been conducted and the electrical distribution equipment is not equipped witharc-flash warning labels.	All costs for installation of required Arc Flash labels and other recommendations per Andeavor standards, discovered through initial evaluation

Fernley Terminal	Electrical drawings(One-Lines, Area Plans) and documentation are not available for the terminal.	All costs to determine if appropriate P&ID’s, plot plans, isometric and electricalone-line drawings and maintenance records are in place, as well as to prepare any required documents.

Fernley Terminal	An underground electrical vault recently caught on fire and needed replacement. The root cause should be investigated and mitigated for all underground cabling.	All costs to conduct an investigation to determine cause of electrical vault fire and to implement projects to address findings to prevent future incidents

Fernley Terminal	No automated fire or gas detection systems were observed; however this is typical for this type of facility.	All costs related to performing an evaluation to determine if additional fire or gas detection is needed and for addressing any identified deficiencies in compliance with NFPA codes and Andeavor fire safety standards

Fernley Terminal	A SCADA system is available for the storage tanks, but it is only visible from the local HMI located on the PLC at the terminal and not in the main office.	All costs to conduct a study to evaluate need for SCADA or similar controls on storage tanks and to implement findings as per Andeavor standards

Schedule VI- Page 59 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement


Site	3^rd Party Contractor Identified Risk	Andeavor Reimbursements
Fernley Terminal	Tanks are not equipped with any remote monitoring, alarms, or interlocks to prevent tank overfill. Tank levels are displayed locally on a PLC HMI, but only text appears when a tank level is high. No shutdowns or audible alarms are in place.	All costs to conduct a study to evaluate need for SCADA or similar controls and for installation of remote monitoring or SCADA control systems, as needed.

Fernley Terminal	Cathodic protection systems do not exist to protect select aboveground storage tank bottoms and buried facility piping in direct soil contact.	All costs to conduct a Cathodic Protection survey and to make recommended repairs to address deficiencies as per Andeavor standards

Fernley Terminal	The stair styles and landings at the rail loading rack do not have guardrail on all sides. Landings are greater than 30” above adjacent grade and require rails for personnel fall protection.	All costs to implement interim mitigations to reduce the risk to personnel and undertake projects to address fall protection concerns at the rail loading rack.

Fernley	The facility does not have a general alarm system to warn personnel on an incident. The emergency response plan indicates that the facility has a general alarm, but this is not accurate based on a review of the site.	All costs for review of Emergency Response Plan and for any modifications needed to comply with Andeavor standards and requirements of Emergency Response Plan including installation of emergency alarm systems

Schedule VI- Page 60 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule VII

Contribution Agreements, Other Transactions and Applicable Terms

Initial Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement, dated as April 26, 2011, among the Partnership, the General Partner, the Operating Company, Andeavor, Tesoro Alaska, TRMC and Tesoro High Plains Pipeline Company LLC

April 26, 2011

April 26, 2013

April 26, 2016

TRMC and Tesoro Alaska

TRMC

April 26, 2021

Yes

Schedule VII- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Amorco Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement dated as of April 1, 2012, among the Partnership, the General Partner, the Operating Company, Tesoro and TRMC

April 1, 2012

April 1, 2014

April 1, 2017

TRMC

April 1, 2022

Yes

Schedule VII- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Long Beach Contribution Agreement

Contribution Agreement

Closing Date

First

Deadline

Date

Second

Deadline

Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third

Deadline Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement executed as of September 14, 2012, among the Partnership, the General Partner, the Operating Company, Andeavor and TRMC

Execution Date is September 14, 2012, and various Effective Times are upon receipt of the Long Beach Approval, the CDFG Approval and the Other Approvals as set forth in the agreement, as applicable

September 14, 2014

September 14, 2017

TRMC

September 14, 2022

Yes

Schedule VII- Page 3 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Anacortes Rail Facility Contribution Agreement

Contribution Agreement

Closing Date

First

Deadline

Date

Second

Deadline

Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third

Deadline Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement executed as of November 15, 2012, among the Partnership, the General Partner, the Operating Company, Andeavor and TRMC

November 15, 2012

November 15, 2014

November 15, 2017

TRMC

November 15, 2022

Schedule VII- Page 4 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

BP Carson Tranche 1 Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement executed as of May 17, 2013, among the Partnership, the General Partner, the Operating Company, Andeavor and TRMC

June 1, 2013

Not Applicable

Schedule VII- Page 5 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

BP Carson Tranche 2 Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement executed as of November 18, 2013, among the Partnership, the General Partner, the Operating Company, Andeavor, TRMC and Carson Cogeneration Company

December 6, 2013

Not Applicable

Schedule VII- Page 6 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

West Coast Assets Contribution Agreement

Contribution Agreement

Closing Date

First Deadline
Date

Second Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third Deadline
Date

Omnibus
Section

5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement executed as of June 23, 2014, among the Partnership, the General Partner, the Operating Company, Tesoro Logistics Pipelines LLC, Andeavor, TRMC and Tesoro Alaska

First Closing Date: July 1, 2014

Second Closing Date has the meaning set forth in the Contribution Agreement

The second (2^nd) anniversary of the First Closing Date or the Second Closing Date, as applicable

With respect to Section 3.1(a): Not applicable

With respect to Section 3.2: The fifth (5^th) anniversary of the First Closing Date or the Second Closing Date, as applicable

Andeavor, TRMC, Tesoro Alaska

The tenth (10^th) anniversary of the First Closing Date or the Second Closing Date, as applicable.

Yes

Schedule VII- Page 7 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2015 Line 88 and Carson Tankage Contribution Agreement

Contribution Agreement

Closing Date

First

Deadline

Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline Date

Omnibus
Section
5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of November 12, 2015, among the Partnership, the General Partner, the Operating Company, Tesoro SoCal Pipeline Company LLC, Andeavor, TRMC and Carson Cogeneration Company

November 12, 2015

November 12, 2017

November 12, 2020

Andeavor, TRMC, Carson Cogen

November 12, 2025

Yes

Schedule VII- Page 8 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2016 Alaska Assets Contribution Agreement

Contribution Agreement

Closing Date

First

Deadline

Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third Deadline
Date

Omnibus
Section
5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of July 1, 2016, among the Partnership, the General Partner, the Operating Company, Tesoro Alaska Company LLC, and Andeavor

KENAI TANKAGE

July 1, 2016

July 1, 2018

July 1, 2021

Tesoro Alaska Company LLC

Not applicable

July 1, 2026

Yes

Contribution, Conveyance and Assumption Agreement effective as of July 1, 2016, among the Partnership, the General Partner, the Operating Company, Tesoro Alaska Company LLC, and Andeavor

ANCHORAGE AND FAIRBANKS TERMINALS

September 16, 2016

September 16, 2018

September 16, 2023

Tesoro Alaska Company LLC

Not applicable

September 16, 2026

Yes

Schedule VII- Page 9 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Martinez Assets Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline

Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third Deadline
Date

Omnibus
Section
5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of November 21, 2016, among the Partnership, the General Partner, the Operating Company, TRMC and Andeavor

November 21, 2016

November 21, 2018

November 21, 2021

TRMC

Not applicable

November 21, 2026

Yes

Schedule VII- Page 10 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Pre-Merger Agreement WNRL Assets

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section
5.1(b)
Applies

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder

October 30, 2017

Not Applicable

Schedule VII- Page 11 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2017 Anacortes Assets Contribution Agreement

Contribution Agreement

Closing Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third Deadline
Date

Omnibus
Section
5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of November 8, 2017, among the Partnership, the Operating Company, TRMC and Andeavor

November 8, 2017

November 8, 2019

November 8, 2022

TRMC

Not applicable

November 8, 2027

Yes

Schedule VII- Page 12 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

2018 Assets Contribution Agreement

Refinery storage, rail, truck, Legacy WesternPermian/4-Corners, Clearbrook tankage, Great Plains/BakkenLink

Contribution Agreement

Closing
Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section
5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of August 6, 2018 (the “2018 Assets Contribution Agreement”), among the Partnership, the Operating Company, TRMC, Western Refining Southwest, Inc. (“WRSW”), Andeavor and the other parties thereto, insofar as it covers the Group B Assets [Bobcat Pipeline, Benny Pipeline, Mesquite Truck Station, Yucca Truck Station, Mason East Station, Wink Station], Group C [Wingate Terminal], Group D Assets [Clearbrook Tankage], Group E [assets associated with Mandan Refinery, Salt Lake Refinery, LARC Refinery Unit and LARW Refinery Unit], and TGPM Units (as such terms are defined in the 2018 Assets Contribution Agreement)

August 6, 2018

August 6, 2020

August 6, 2023

TRMC

WRSW

Western Refining Company, L.P. (“WRCLP”)

Not applicable

August 6, 2028

Yes

Schedule VII- Page 13 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Aranco Pipeline, Jal NGL Storage Facility

Contribution Agreement

Closing
Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section 5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of August 6, 2018, among the Partnership, the Operating Company, TRMC, WRSW, Andeavor and the other parties thereto, insofar as it covers the Group A Assets [Jal NGL Storage Facility] and the Group G Assets [Aranco Pipeline]

August 6, 2018

Not applicable

August 6, 2028

LA Refinery Interconnecting Pipeline, Conan, Rio Pipeline, Asphalt Terminals, MPL

Contribution Agreement

Closing
Date

First
Deadline
Date

Second
Deadline
Date

Andeavor
Indemnifying
Parties

Andeavor
Indemnified
Parties

Third
Deadline
Date

Omnibus
Section 5.1(b)
Applies

Contribution, Conveyance and Assumption Agreement effective as of August 6, 2018, among the Partnership, the Operating Company, TRMC, WRSW, Andeavor and the other parties thereto, insofar as it covers the Group F Assets [LA Refinery Interconnecting Pipeline], the MPL Units, WRCG Units, WRDBS Units, ATL Units, and Andeavor Rio Units (as such terms are defined in the 2018 Assets Contribution Agreement)

August 6, 2018

Not applicable

August 6, 2028

No*

*	Special indemnities per Schedule IX

Schedule VII- Page 14 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule VIII

Administrative Fee and Indemnification Deductibles

Monthly Administrative Fee

$1,383,333

Annual Environmental Deductible

$1,000,000

Annual ROW Deductible

$1,000,000

Schedule VIII- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Schedule IX

Special Indemnification Provisions

For Initial Contribution Agreement listed on Schedule VII:

None.

For Amorco Contribution Agreement listed on Schedule VII:

Addition to Right of Way Indemnification. As of the Closing Date for the Amorco Contribution Agreement, TRMC shall own the leasehold rights in the “Wharf Lease” issued by the California State Lands Commission and the easements, rights of way and permits for the “SHPL,” all as defined in the Amorco Contribution Agreement, and the Partnership Group shall provide operational, maintenance and management services with respect to such Assets pursuant to the MTUTA. Title to Wharf Lease rights and the SHPL are scheduled to be contributed to the Partnership Group at a later date, as set forth in the Amorco Contribution Agreement. The Right of Way Indemnification set forth in Section 3.2 herein applies to the extent that a Loss arises with respect to a Partnership Group Member’s interests under the MTUTA before title to such Assets is contributed to the Partnership Group Member or with respect to a Partnership Group Member’s failure to become the owner of such valid and indefeasible easement rights or fee ownership or leasehold interests in such Assets after they are finally contributed to the Partnership Group as contemplated in the Amorco Contribution Agreement. The Closing Date provided for in this Agreement shall be as set forth above, without regard to when title to these Assets is finally contributed to a Partnership Group Member.

For Long Beach Contribution Agreement listed on Schedule VII:

Addition to Right of Way Indemnification. As of the Closing Date for the Long Beach Contribution Agreement, TRMC shall own the leasehold rights in the “Terminal Lease” issued by the Port of Long Beach and the easements, rights of way and permits for the “Terminal Pipelines,” all as defined in the Long Beach Contribution Agreement, and the Partnership Group shall provide operational, maintenance and management services with respect to such Assets pursuant to the Long Beach Operating Agreement, as defined in the Long Beach Contribution Agreement. Title to Terminal Lease rights and the Terminal Pipelines are scheduled to be contributed to the Partnership Group at a later date, as set forth in the Long Beach Contribution Agreement. The Right of Way Indemnification set forth in Section 3.2 herein applies to the extent that a Loss arises with respect to a Partnership Group Member’s interests under the BAUTA before title to such Assets is contributed to the Partnership Group Member or with respect to a Partnership Group Member’s failure to become the owner of such valid and indefeasible easement rights or fee ownership or leasehold interests in such Assets after they are finally contributed to the Partnership Group as contemplated in the Long Beach Contribution Agreement. The Closing Date provided for in this Agreement shall be as set forth above, without regard to when title to these Assets is finally contributed to a Partnership Group Member.

Schedule IX- Page 1 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For Anacortes Rail Facility Contribution Agreement listed on Schedule VII:

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Anacortes Track Use and Throughput Agreement among the General Partner, the Partnership, the Operating Company and TRMC, (iii) the Anacortes Mutual Track Use Agreement among the General Partner, the Partnership, the Operating Company and TRMC, and (iv) the Ground Lease between TRMC and the Operating Company, all dated as of November 15, 2012, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. For the avoidance of doubt, the indemnification provisions of the Fourth Amended and Restated Omnibus Agreement shall be subordinate to the respective indemnification provisions of each of the other agreements referenced above.

For BP Carson Tranche 1 Contribution Agreement listed on Schedule VII:

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the BP Carson Tranche 1 Contribution Agreement listed onSchedule VII, (iii) the Master Terminalling Services Agreement – Southern California among TRMC, the General Partner, the Partnership and the Operating Company dated as of June 1, 2013, as amended, and (iv) the Carson Storage Services Agreement among TRMC, the General Partner, the Partnership and the Operating Company dated as of June 1, 2013, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Carson Assets Indemnity Agreement, the provisions of the Carson Assets Indemnity Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements. Notwithstanding anything to the contrary in the Fourth Amended and Restated Omnibus Agreement, the indemnification provisions of Sections 3.2 and 3.5 thereof shall not apply to the Assets as defined in the BP Carson Tranche 1 Contribution Agreement listed onSchedule VII.

Schedule IX- Page 2 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For BP Carson Tranche 2 Contribution Agreement listed on Schedule VII:

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the BP Carson Tranche 2 Contribution Agreement listed onSchedule VII, (iii) the Amended and Restated Master Terminalling Services Agreement – Southern California among TRMC, the General Partner, the Partnership and the Operating Company dated as of December 6, 2013, (iv) the Long Beach Storage Services Agreement among TRMC, the General Partner, the Partnership and the Operating Company dated as of December 6, 2013, (v) the Berth 121 Operating Agreement between the Operating Company and Carson Cogeneration Company, dated as of December 6, 2013, (vi) the Terminals 2 and 3 Operating Agreement among the Partnership, the General Partner, the Operating Company and TRMC, dated as of December 6, 2013, (vii) the Amended and Restated Long Beach Berth Access Use and Throughput Agreement among the Partnership, the General Partner, the Operating Company and TRMC, dated as of December 6, 2013, (viii) the Long Beach Berth Throughput Agreement among the Partnership, the General Partner, the Operating Company, TRMC and Carson Cogeneration Company, dated as of December 6, 2013, (ix) the SoCal Transportation Services Agreement between TRMC and Tesoro SoCal Pipeline Company LLC, dated as of December 6, 2013, (x) the Long Beach Pipeline Throughput Agreement among the Partnership, the General Partner, the Operating Company and TRMC, dated as of December 6, 2013, (xi) the Carson Coke Handling Services Agreement among the Partnership, the General Partner, the Operating Company and TRMC, dated as of December 6, 2013, (xii) the Coke Barn Lease Agreement between the Operating Company and TRMC, dated as of December 6, 2013 and (xiii) the Terminals 2 and 3 Ground Lease between the Operating Company and TRMC, dated as of December 6, 2013, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Carson Assets Indemnity Agreement, the provisions of the Carson Assets Indemnity Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

Schedule IX- Page 3 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For West Coast Assets Contribution Agreement listed on Schedule VII:

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Terminalling Services Agreement – Nikiski, among the General Partner, the Partnership, the Operating Company and Tesoro Alaska, (iii) the Terminalling Services Agreement – Anacortes, among the General Partner, the Partnership, the Operating Company and TRMC, (iv) the Terminalling Services Agreement – Martinez, among the General Partner, the Partnership, the Operating Company and TRMC, and (v) the Storage Services Agreement – Anacortes, the Terminalling Services Agreement – Anacortes, among the General Partner, the Partnership, the Operating Company and TRMC, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

For 2015 Line 88 and Carson Tankage Contribution Agreement listed on Schedule VII:

Other. Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Carson II Storage Agreement, and (iii) Amendment No. 1 to the (SoCal) Transportation Services Agreement dated November 12, 2015, between TRMC and Tesoro SoCal Pipeline Company LLC, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

For 2016 Alaska Assets Contribution Agreement listed on Schedule VII:

The Partnership Group agree that, after the Effective Date, they shall not knowingly breach any covenants of TAC contained in that certain Asset Purchase Agreement dated as of November 20, 2015 by and between Flint Hills Resources Alaska, LLC and TAC (the “Flint Hills APA”) as if the Partnership Group were parties thereto instead of TAC.

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Kenai Storage Services Agreement, and (iii) the Alaska Terminalling Services Agreement, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

Schedule IX- Page 4 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Notwithstanding any other provisions of the Fourth Amended and Restated Omnibus Agreement, the indemnification obligations of the Andeavor Entities under Section 3.1(a) of the Fourth Amended and Restated Omnibus Agreement with regard to the 2016 Environmental Consent Decree are limited to reimbursement for any capital expenditures that the Partnership Group may be required to make to comply therewith and any fines or other penalties which may be levied for any failure therewith (except to the extent such fines or other penalties are the result of the failure of the Partnership Group to comply therewith with regard to the contributed assets) and such indemnification obligations shall extend to or cover any increased ongoing operating or maintenance expenses incurred by the Partnership Group in connection with their compliance therewith.

For Martinez Assets Contribution Agreement listed on Schedule VII:

Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Martinez Storage Services Agreement, dated as of November 21 2016, between TRMC and the Operating Company; (iii) the Avon Marine Terminal Operating Agreement, dated as of November 21 2016, between TRMC and the Operating Company; (iv) the License Agreement, dated as of November 21 2016, between TRMC and the Operating Company; and (v) the Avon Marine Terminal Sublease Agreement and the Avon Marine Terminal Use and Throughput Agreement to be entered into between TRMC and the Operating Company pursuant to Section 2.5 of the Martinez Assets Contribution Agreement, the parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

For Assets owned by WNRL on the Closing Date of the Merger Agreement and acquired by the Partnership pursuant to the Merger Agreement by virtue of its acquisition of WNRL thereunder:

Notwithstanding any other provisions of the Fourth Amended and Restated Omnibus Agreement, the Parties hereto agree that the indemnification provisions in Article VI of the SERA shall control and prevail over any of the provision of the Fourth Amended and Restated Omnibus Agreement, other than Section 3.5(b), and shall be the exclusive provisions for all indemnification obligations relating to the subject matter of the indemnities so provided in Article VI of the SERA.

Schedule IX- Page 5 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

For 2017 Anacortes Assets Contribution Agreement listed on Schedule VII:

1. Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Anacortes Storage Services Agreement – Anacortes II, dated as of November 8, 2017, between TRMC and the Operating Company; (iii) the Anacortes Marine Terminal Operating Agreement, dated as of November 8, 2017, between TRMC and the Operating Company; (iv) the Pipeline Transportation Services Agreement – Anacortes Short Haul Pipelines dated as of November 8, 2017, between TRMC and the Operating Company, (v) the Ground Lease dated as of November 8, 2017, between TRMC and the Operating Company with respect to the real property underlying the Tankage; (vi) the Second Amendment dated as of November 8, 2017, to that certain Ground Lease between TRMC and the Operating Company relating to a portion of the Anacortes Refinery dated as of November 15, 2012, (vii) the First Amendment dated as of November 8, 2017, to that certain Ground Lease between TRMC and the Operating Company relating to a portion of the Anacortes Refinery dated as of July 1, 2014, (viii) the Sublease Rights and Escrow Agreement between TRMC and the Operating Company dated as of November 8, 2017 and (ix) the Anacortes Marine Terminal Use and Throughput Agreement to be entered into between TRMC and the Operating Company pursuant to Sublease Rights and Escrow Agreement, the Parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements.

2. The expenses reimbursable to the Partnership Group for repairs and maintenance of any aboveground storage tanks, included within the Assets conveyed, contributed or otherwise transferred pursuant to the 2017 Anacortes Contribution Agreement (“2017 Anacortes Storage Tanks”), under Section 5.1(b) of the Fourth Amended and Restated Omnibus Agreement required to bring any of the 2017 Anacortes Storage Tanks into compliance with API Standard 653 shall include the expense of any required earthwork (such as new sandbeds) to restore such storage tanks to active service; provided that such expenses shall not include any expenses for Covered Environmental Losses, which shall continue to be governed by Section 3.1 of the Fourth Amended and Restated Omnibus Agreement and the provisions of paragraph 3 below.

3. For any of the 2017 Anacortes Storage Tanks for which the first API 653 internal inspection has not been completed prior to the fifth anniversary of the applicable Closing Date, the Operating Company shall conduct a detailed review of all available inspection records or other reports applicable to such storage tanks and shall make inspections of the visible external condition of the tanks prior to such fifth anniversary of the applicable Closing Date. If such review and inspection indicates, in the reasonable judgment of the Operating Company, that there exists a reasonable concern regarding the structural integrity of any such tank, then:

(a) The Operating Company shall provide written notice of such reasonable concern to TRMC, including a detailed description of the Operating Company’s reasons for such concern;

(b) The Operating Company shall schedule the first API 653 internal inspection of any such tank at the soonest practical date; and

Schedule IX- Page 6 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

(c) The Identification Deadline with regard to any Covered Environmental Losses caused by any release from such tank first identified at the time of such first API 653 internal inspection of such tank shall be extended for a period of sixty (60) days following the completion of such first API 653 internal inspection of such tank.

For 2018 Assets Contribution Agreement listed on Schedule VII:

Defined terms used in this portion of Schedule IX without definition will have the meaning given such terms in the 2018 Assets Contribution Agreement.

1. Notwithstanding any other provisions of (i) the Fourth Amended and Restated Omnibus Agreement, (ii) the Master Terminaling Services Agreement, dated as of August 6, 2018, by between those parties identified as “Providers” and those identified as “Customers” on Schedule I thereto, (iii) Transportation Services Agreement (LAR Interconnecting Pipelines) dated August 6, 2018, by and between Tesoro SoCal Pipeline Company LLC and Tesoro Refining & Marketing Company LLC, (iv) Construction Service Agreement (Los Angeles Refinery Interconnecting Pipelines) dated August 6, 2018, by and between Tesoro SoCal Pipeline Company LLC and Tesoro Refining & Marketing Company LLC, (v) Asphalt Terminalling, Transportation and Storage Services Agreement dated August 6, 2018, by and between Western Refining Company, L.P. and Asphalt Terminals LLC, (vi) Master Unloading and Storage Agreement dated August 6, 2018, by and between Western Refining Pipeline, LLC and Western Refining Company, L.P., (vii) Special Warranty Deed for Clearbrook dated August 6, 2018, between WRSW and the Operating Company, (viii) Special Warranty Deed for Wingate Terminal dated August 6, 2018, between WRSW and Western Refining Terminals, LLC (“WRT”), (ix) Special Warranty Deed for Mason East Station dated August 6, 2018, between WRSW and Western Refining Pipeline, LLC (“WRP”), (x) Special Warranty Deed for Conan terminal dated August 6, 2018, between Western Refining Conan Gathering, LLCand WRT, (xi) Special Warranty Deed for Jal Terminal dated August 6, 2018, between WRCL and WRT, (xii) Conveyance, Bill of Sale, Assignment and Assumption for Benny Pipeline dated August 6, 2018, between WRSW and WRP, (xiii) Conveyance, Bill of Sale, Assignment and Assumption for Bobcat Pipeline dated August 6, 2018, between WRSW and WRP, (xiv) Conveyance, Bill of Sale, Assignment and Assumption for Conan pipeline dated August 6, 2018, between WRSW and Western Refining Conan Gathering, LLC, (xv) Conveyance, Bill of Sale, Assignment and Assumption for Aranco Pipeline dated August 6, 2018, between St. Paul Park Refining Co. LLC and the Operating Company, and (xvi) Conveyance, Bill of Sale, Assignment and Assumption for Clearbrook dated August 6, 2018, between WRSW and the Operating Company, the Parties hereto agree that the indemnification provisions of any of those agreements shall control over any of the other agreements to the extent the subject matter of the indemnification is specifically referenced or provided for in that agreement. In the event of a conflict of provisions of any of the above-referenced agreements and the Fourth Amended and Restated Omnibus Agreement, the provisions of the Fourth Amended and Restated Omnibus Agreement shall prevail with respect to issues related to the contribution of the assets described therein, but not with respect to the ordinary operations of such assets as set forth in the above-referenced agreements. With respect to the LA Refinery Interconnecting Pipeline, the Aranco Pipeline, and the assets conveyed to the Partnership Group as a result of the transfer of the MPL Units, the WRCG Units, the WRDBS Units, the ATL

Schedule IX- Page 7 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Units, and the Andeavor Rio Units by the Andeavor Entities to the Partnership Group, the indemnities in those other agreements and in this Schedule IX shall be the exclusive indemnity obligations between the Andeavor Entities and the Partnership Group, and the indemnities in Sections 3 and 5 of the Fourth Amended and Restated Omnibus Agreement shall not apply.

2. With respect to (i) the Ground Lease dated August 6, 2018 for Mandan Refinery between TRMC and the Operating Company, and (ii) Ground Lease dated August 6, 2018 for Salt Lake Refinery between TRMC and the Operating Company, which include warranties of quiet enjoyment and indemnity obligations governed by the Master Terminalling Services Agreement and the Fourth Amended and Restated Omnibus Agreement, the Fourth Amended and Restated Omnibus Agreement shall prevail in the event of any conflict with the Master Terminalling Services Agreement.

3. With respect to the surface and subsurface of the lands on the LARW Refinery Unit, LARC Refinery Unit and LA Refinery Interconnecting Pipeline for which access is licensed to the Partnership Group by the Andeavor Entities pursuant to the License Agreement referenced in the 2018 Assets Contribution Agreement, (i) the Andeavor Entities shall remain liable and responsible for all liabilities, costs and expenses (including without limitation, response and remediation costs) arising by reason of contamination by hazardous substances to the extent (a) caused by TRMC while it held fee title to the land and existed on or before the date of the 2018 Assets Contribution Agreement or (b) resulting from future operations by TRMC on the land after the date of the 2018 Assets Contribution Agreement while TRMC holds fee title to the property, and (ii) liabilities regarding environmental liabilities arising from TRMC’s operation on such lands on or after the date of the 2018 Assets Contribution Agreement shall be as provided in the Master Terminalling and Storage Agreement or the Pipeline Transportation Agreement, as applicable.

4. Before the effective date of the 2018 Assets Contribution Agreement, Western Refining Company, L.P., a subsidiary of Andeavor, acquired certain asphalt terminals and other assets under an Asset Purchase Agreement dated February 9, 2018 (the “Asphalt Terminals APA”), and TRMC acquired the Andeavor Rio Units and the Andeavor CD Units under a Purchase and Sale Agreement dated December 26, 2017 (the “Rio Pipeline APA”). With respect to the assets acquired under the Asphalt Terminals APA and the assets and interests acquired under the Rio Pipeline APA, the Andeavor Entities shall provide to the Partnership Group the benefit of all indemnification rights from third parties that the Andeavor Entities hold with respect to such assets by reason of the Asphalt Terminals APA and the Rio Pipeline APA.

The Partnership Group agrees that, after the effective date of the 2018 Assets Contribution Agreement, they shall not do anything that would be considered a breach of the Asphalt Terminals APA or the Rio Pipeline APA as if the Partnership Group were parties thereto instead of Western Refining Company, L.P. or TRMC, respectively, and the Partnership Group will defend, indemnify and hold harmless the Andeavor Group against all Losses due to any Partnership Group Member’s breach thereof.

Schedule IX- Page 8 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

5. The Partnership Group Member that is the assignee of an assigned contracts listed on Schedule B to the 2018 Assets Contribution Agreement agrees to defend, indemnify and hold harmless the Andeavor Group against all Losses arising under the assigned contract due to any Partnership Group Member’s failure to perform its obligations under the assigned contract.

6. To the extent that any Andeavor Entity remains the guarantor of any obligations of a company or other entity that is contributed to the Partnership Group through the WRS Unit Contribution, the Partnership Group agrees to defend, indemnify and hold harmless the Andeavor Group against all Losses arising under any such guaranty.

Schedule IX- Page 9 to

Second Amended and Restated Schedules to Fourth Amended and Restated Omnibus Agreement

Andeavor Logistics (ANDX) Inactive 8-KEntry into a Material Definitive Agreement