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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 Form 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
Commission file number 001-35714
MPLX LP
(Exact name of registrant as specified in its charter)
Delaware27-0005456
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
200 E. Hardin Street, Findlay, OH 45840-3229
(Address of principal executive offices) (Zip code)
(419) 421-2414
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Units Representing Limited Partnership InterestsMPLXNew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes   x    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x   No  ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer x    Accelerated filer ¨    Non-accelerated filer ¨    
Smaller reporting company Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.   x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes    No   x
The aggregate market value of common units held by non-affiliates as of June 30, 2020 was approximately $6.8 billion. This amount is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 30, 2020. Common units held by executive officers and directors of the registrant and its affiliates are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers and those of its affiliates to be affiliates.
MPLX LP had 1,037,169,607 common units outstanding at February 12, 2021.

DOCUMENTS INCORPORATED BY REFERENCE: None


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  Page
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Item 15.
Item 16.


Unless the context otherwise requires, references in this report to “MPLX LP,” “MPLX,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries. Additionally, throughout this Annual Report on Form 10-K, we have used terms in our discussion of the business and operating results that have been defined in our Glossary of Terms.


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Glossary of Terms
The abbreviations, acronyms and industry terminology used in this report are defined as follows:
AROAsset retirement obligation
ASCAccounting Standards Codification
ASUAccounting Standards Update
ATM ProgramAn at-the-market program for the issuance of common units
Barrel (Bbl)One stock tank barrel, or 42 United States gallons of liquid volume, used in reference to crude oil or other liquid hydrocarbons.
Bcf/dOne billion cubic feet per day
BtuOne British thermal unit, an energy measurement
CondensateA natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
DCF (a non-GAAP financial measure)Distributable Cash Flow
DOTUnited States Department of Transportation
EBITDA (a non-GAAP financial measure)Earnings Before Interest, Taxes, Depreciation and Amortization
EPAUnited States Environmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
GAAPAccounting principles generally accepted in the United States of America
IRSInternal Revenue Service
LIBORLondon Interbank Offered Rate
MarkWest MergerOn December 4, 2015, a wholly-owned subsidiary of MPLX merged with MarkWest Energy Partners, L.P. (“MarkWest”)
mbblsThousands of barrels
mbpdThousand barrels per day
mcfOne thousand cubic feet
MergerMPLX acquisition by merger of Andeavor Logistics LP (“ANDX”) on July 30, 2019
MMBtuOne million British thermal units, an energy measurement
MMcf/dOne million cubic feet per day
NGLNatural gas liquids, such as ethane, propane, butanes and natural gasoline
NYSENew York Stock Exchange
OTCOver-the-Counter
Partnership AgreementSixth Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 1, 2021
PHMSAPipeline and Hazardous Materials Safety Administration
PPIProducer Price Index
Predecessor
Collectively:
- The related assets, liabilities and results of operations of Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) prior to the date of the acquisition, March 1, 2017, effective January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT
- The related assets, liabilities and results of operations of ANDX prior to the date of the merger, July 30, 2019, effective October 1, 2018.
Realized derivative gains/lossesThe gain or loss recognized when a derivative matures or is settled
SECUnited States Securities and Exchange Commission
Unrealized derivative gains/lossesThe gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling
USCGUnited States Coast Guard
VIEVariable interest entity
Wholesale ExchangeThe transfer to MPC of the Western wholesale distribution business, which MPLX acquired as a result of its acquisition of ANDX, on July 31, 2020.


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Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words such as “anticipate,” “believe,” “commitment,” “could,” “design,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “imply,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “project,” “proposition,” “prospective,” “pursue,” “seek,” “should,” “strategy,” “target,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.

Forward-looking statements include, among other things, statements regarding:

future financial and operating results;
the success or timing of completion of ongoing or anticipated capital or maintenance projects;
the amount and timing of future distributions or unit repurchases; and
the anticipated effects of actions of third parties such as competitors, activist investors or federal, foreign, state or local regulatory authorities or plaintiffs in litigation.

Our forward-looking statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:

general economic, political or regulatory developments, including changes in governmental policies relating to refined petroleum products, crude oil, natural gas or NGLs, regulation or taxation and other economic and political developments;
the magnitude and duration of the COVID-19 pandemic and its restrictions, including travel restrictions, business and school closures, increased remote work, stay-at-home orders and other actions taken by individuals, governments and the private sector to stem the spread of the virus;
the ability of Marathon Petroleum Corporation (“MPC”) to achieve its strategic objectives and the effects of those strategic decisions on us;
further impairments;
negative capital market conditions, including an increase of the current yield on common units;
the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;
the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, and the effects of any such divestitures on the business, financial condition, results of operations and cash flows;
adverse changes in laws including with respect to tax and regulatory matters;
the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models;
the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products;
volatility in or degradation of market and industry conditions;
changes to the expected construction costs and timing of projects and planned investments, and the ability to obtain regulatory and other approvals with respect thereto;
completion of midstream infrastructure by competitors;
disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;
the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;
modifications to financial policies, capital budgets, and earnings and distributions;
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the ability to manage disruptions in credit markets or changes to credit ratings;
compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;
adverse results in litigation;
the reliability of processing units and other equipment;
the effect of restructuring or reorganization of business components;
the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;
foreign imports and exports of crude oil, refined products, natural gas and NGLs;
changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks and refined products;
the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
actions taken by our competitors, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;
expectations regarding joint venture arrangements and other acquisitions or divestitures of assets;
midstream and refining industry overcapacity or under capacity;
accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, or those of our suppliers or customers;
acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or transport crude oil, natural gas, NGLs or refined products;
political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs or other hydrocarbon-based products; and
the other factors described in Item 1A. Risk Factors.

We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.
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Part I

Item 1. Business

OVERVIEW

We are a diversified, large-cap master limited partnership (“MLP”) formed in 2012 by MPC (as our sponsor) that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. Our assets include a network of crude oil and refined product pipelines; an inland marine business; light-product, asphalt, heavy oil and marine terminals; storage caverns; refinery tanks, docks, loading racks, and associated piping; crude oil and natural gas gathering systems and pipelines; as well as natural gas and NGL processing and fractionation facilities. The operation of these assets are conducted in our Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”) operating segments. Our assets are positioned throughout the United States as depicted in the map below. Our L&S segment primarily engages in the transportation, storage, distribution and marketing of crude oil, asphalt and refined petroleum products. The L&S segment also includes the operation of our inland marine business, terminals, rail facilities, storage caverns and refining logistics. Our G&P segment primarily engages in the gathering, processing and transportation of natural gas as well as the gathering, transportation, fractionation, storage and marketing of NGLs. For more information on these segments, see Our Operating Segments discussion below. The map below and Item 2. Properties provide information about our assets as of December 31, 2020:

mplx-20201231_g1.jpg

We continue to have a strategic relationship with MPC, which is a large source of our revenues. We have executed numerous long-term, fee-based agreements with minimum volume commitments with MPC which provide us with a stable and predictable revenue stream and source of cash flows. As of December 31, 2020, MPC owned our general partner and approximately 62 percent of our outstanding common units. MPC will continue to be an important source of our revenues and cash flows for the foreseeable future. We also have long-term relationships with a diverse set of producer customers in many crude oil and natural gas resource plays, including the Permian Basin, Marcellus Shale, Utica Shale, STACK Shale and Bakken Shale, among others.

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The growth of our business has provided us with the financial flexibility to maintain an investment grade credit profile, fund our organic growth capital plan with operating cash or debt, create the opportunity to execute a unit repurchase program, and achieve excess cash flow after capital investments and distributions. We continue to evaluate opportunities to develop, expand and participate in projects which complement our existing assets in addition to evaluating non-organic growth opportunities through third-party midstream acquisitions to enhance our existing geographic footprint or expand our activities into new areas. We also assess opportunities to optimize our portfolio of assets through strategic dispositions.

2020 RESULTS

The following table summarizes the operating performance for each segment for the year ended December 31, 2020. For further discussion of our segments and a reconciliation to our Consolidated Statements of Income, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Item 8. Financial Statements and Supplementary Data – Note 10.
mplx-20201231_g2.jpg
(1)    Includes impairment expense of $1.3 billion related to three equity method investments within our G&P segment.
(2)    Includes impairment expense for goodwill, equity method investments, intangible assets and property, plant and equipment of $1.8 billion, $1.3 billion, $177 million and $174 million, respectively.

2020 ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS

On November 2, 2020, MPLX announced the board authorization of a unit repurchase program for the repurchase of up to $1 billion of MPLX’s outstanding common units held by the public. MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated unit repurchases or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of repurchases will depend upon several factors, including market and business conditions, and repurchases may be initiated, suspended or discontinued at any time. The repurchase authorization has no expiration date. As of December 31, 2020, 1,473,843 common units held by the public have been repurchased and $967 million remained outstanding under the program for future repurchases.
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On August 18, 2020, MPLX issued $3 billion aggregate principal amount of new senior notes consisting of $1.5 billion aggregate principal amount of 1.750 percent senior notes due March 2026 and $1.5 billion aggregate principal amount of 2.650 percent senior notes due August 2030. The net proceeds were used to repay the $1.0 billion of outstanding borrowings under the MPLX Term Loan Agreement, to repay the $1.0 billion aggregate principal amount of floating rate notes due September 2021, to redeem all of the $450 million aggregate principal amount of 6.375 percent senior notes due May 2024, to reduce amounts outstanding under the MPLX Credit Agreement at the time, and to redeem the $300 million aggregate principal amount of 6.250 percent senior notes due October 15, 2022.
On July 31, 2020, MPLX completed the transfer of Western Refining Wholesale, LLC (“WRW”) to Western Refining Southwest, Inc. (now known as Western Refining Southwest LLC) (“WRSW”), a wholly owned subsidiary of MPC, in exchange for the redemption of 18,582,088 MPLX common units held by WRSW (the “Wholesale Exchange”), valued at $340 million. The transaction effects the transfer to MPC of the Western wholesale distribution business that MPLX acquired as a result of its acquisition of ANDX.
During the year, our sponsor progressed certain strategic priorities to lay a foundation for long-term success, including plans to optimize its assets and structurally lower costs in 2021 and beyond, which included an involuntary workforce reduction plan. The workforce reduction plan, together with employee reductions resulting from MPC's indefinite idling of its Martinez, California and Gallup, New Mexico refineries, affected approximately 2,050 employees. All of the employees that conduct MPLX’s business are directly employed by affiliates of MPC, and certain of those employees were affected by MPC’s workforce reductions. During 2020, MPLX reimbursed MPC $37 million related to severance and employee benefits related expenses that MPC recorded in connection with its workforce reductions.
We previously announced a goal to reduce planned capital spending for 2020 by approximately $700 million from our initial plan, which we were able to achieve.
The outbreak of COVID-19 and its development into a pandemic in March 2020 resulted in significant economic disruption globally. Actions taken by various governmental authorities, individuals and companies around the world to prevent the spread of COVID-19 through social distancing have restricted travel, many business operations, public gatherings and the overall level of individual movement and in-person interaction across the globe. Although there have been some signs of economic improvement since that time, these events significantly reduced global economic activity and resulted in a decline in the demand for the midstream services we provide beginning with the first quarter of 2020. Macroeconomic conditions and global geopolitical events have also resulted in significant price volatility related to those aforementioned products. We responded to the impacts that these matters had on our business by:

Taking actions to reduce operating expenses across the business, including the deferral of certain expense projects
Continuing to evaluate and high-grade our capital portfolio

During the first quarter of 2020, the overall deterioration in the economy and the environment in which MPLX and its customers operate, as well as a sustained decrease in unit price, were considered triggering events resulting in impairments of the carrying value of certain assets. We recognized impairments related to goodwill, certain equity method investments and certain long-lived assets (including intangibles), within our G&P segment. Many of our producer customers refined and updated production forecasts in response to the current environment, which impacted their current and expected future demand for our services, including the future utilization of our assets. Additionally, certain of our contracts have commodity price exposure, including NGL prices, which have experienced increased volatility as noted above.
On March 18, 2020, MPC announced the unanimous decision of its board of directors to maintain MPC’s current midstream structure, with MPC remaining the general partner of MPLX. This was a result of a comprehensive evaluation by a special committee formed by MPC’s board of directors, which included extensive input from multiple external advisors and significant feedback from investors.

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RECENT DEVELOPMENTS

In line with previously announced efforts around portfolio optimization, the company closed on the sale of its Javelina plant in Corpus Christi, Texas, on February 12, 2021.
On January 28, 2021, we announced the board of directors of our general partner had declared a distribution of $0.6875 per common unit that was paid on February 12, 2021 to common unitholders of record on February 8, 2021.
On December 29, 2020, MPLX announced the redemption of all the $750 million outstanding aggregate principal amount of 5.250 percent senior notes due January 15, 2025, including approximately $42 million aggregate principal amount of senior notes issued by Andeavor Logistics LP and Tesoro Logistics Finance Corp. The notes were redeemed on January 15, 2021 at a price equal to 102.625 percent of the principal amount.

BUSINESS STRATEGIES

Enhance Cash Flow Stability: We are focused on growing our fee-based services through long-term contracts which provide through-cycle cash flow stability. Planned investments in long-haul pipelines are expected to connect supply to demand markets while adding a source of stable cash flow to the company and expanding our export capabilities to enhance our ability to meet significant growing market needs both domestically and globally.

Continued Capital Discipline and Focus on Lowering Cost Structure: We are focused on lowering our overall cost structure and being disciplined in capital allocation. This means lowering our costs in all aspects of our business and challenging ourselves to be disciplined in every expense dollar we spend across our organization. We look to high-grade our portfolio of investment opportunities to ensure efficient deployment of capital focusing on projects with the highest returns.

Generate Excess Cash: We maintain our goal to achieve excess free cash flow, net of both capital investments and distributions, for 2021. We expect to achieve this through a combination of continued earnings growth and capital discipline. We believe generating excess cash flow will broaden our value-creation options for our unit holders and enhance our long-term financial flexibility.

Maintain Safe and Reliable Operations: We believe that providing safe, reliable and efficient services is a key component in generating stable cash flows. We are committed to maintaining and improving the safety, reliability and efficiency of our operations. Our intent is to continue promoting high standards for safety and environmental stewardship.

Commitment to Corporate Social Responsibility: We look forward to continuing our ESG journey and our commitment to stakeholder engagement with our people, business partners, customers, and communities.


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ORGANIZATIONAL STRUCTURE

The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 12, 2021.

mplx-20201231_g3.jpg

We are an MLP with outstanding common units held by MPC and public unitholders as well as two series of preferred units. Our common units are publicly traded on the NYSE under the symbol “MPLX.” Our Series A preferred units rank senior to all common units and pari passu with our Series B preferred units with respect to distributions and rights upon liquidation. The holders of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater of $0.528125 per unit or the amount of distributions they would have received on an as converted basis. The holders of the Series B preferred units are entitled to receive a fixed annual distribution equal to $68.75 per unit, per annum, payable semi-annually in arrears on February 15 and August 15, or the first business day thereafter, up to and including February 15, 2023. After February 15, 2023, the holders of Series B preferred units are entitled to receive cumulative, quarterly distributions payable in arrears on the 15th day of February, May, August and November of each year, or the first business day thereafter, based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent.

INDUSTRY OVERVIEW

As of December 31, 2020, our diversified services in the midstream sector are across the hydrocarbon value chain. The types of services provided by the midstream sector, broken down by our segments, are as follows:

L&S:

The midstream sector plays a crucial role in the oil and gas industry by providing transportation, storage and marketing services across the hydrocarbon value chain as depicted below.

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mplx-20201231_g4.jpg

Crude oil is the primary raw material for transportation fuels and the basis for many products, including plastics, petrochemicals and heating oil for homes. Pipelines bring advantaged North American crude oil from the upper Great Plains, Louisiana, Texas, Canada and West Coast to numerous refineries throughout the United States. Terminals provide for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products via pipeline, rail, marine and over-the-road modes of transportation. This network of logistics infrastructure also allows for export opportunities by connecting supply to global demand markets. The hydrocarbon market is often volatile and the ability to take advantage of fast-moving market conditions is enhanced by the ability to store crude oil and other hydrocarbon-based products at tank farms, caverns, and tanks at refineries and terminals. The ability to store both crude and refined petroleum products provides flexibility and logistics optionality which allows participants within the industry to take advantage of changing market conditions.
G&P:

The midstream natural gas industry is the link between the exploration for, and production of, natural gas and the delivery of its hydrocarbon components to end-use markets. The components of this value chain are graphically depicted and further described below:

mplx-20201231_g5.jpg

Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, a network of pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems then transport raw, or untreated, natural gas to a central location for treating and processing.
Processing. Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to as “y-grade”). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and commercial use.
Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator.
Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas is delivered to downstream transmission pipelines and NGL components are stored, transported and marketed to end-use markets.

Due to advances in well completion technology and horizontal drilling techniques, unconventional sources, such as shale and tight sand formations, have become a source of current and expected future natural gas production. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing/fractionating plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the shale plays will likely have a competitive advantage. Well-positioned operations allow access to all major NGL markets and provide for
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the development of export solutions for producers. This proximity is enhanced by infrastructure build-out and pipeline projects.

OUR RELATIONSHIP WITH MPC

One of our competitive strengths is our strategic relationship with MPC, which is the largest crude oil refiner in the United States in terms of refining capacity. MPC owns and operates 13 refineries in the West Coast, Gulf Coast and Mid-Continent regions of the United States and distributes refined products through transportation, storage, distribution and marketing services provided by its midstream segment, which primarily consists of MPLX. MPLX, through its fuels distribution services, distributes refined products under the Marathon brand through an extensive network of retail locations owned or operated by independent entrepreneurs across the United States.

MPC retains a significant interest in us through its non-economic ownership of our general partner and holding approximately 62 percent of the outstanding common units of MPLX as of December 31, 2020. Given MPC’s significant interest in us, we believe MPC will promote and support the successful execution of our business strategies.

OUR OPERATING SEGMENTS

We conduct our operations in two segments, which include L&S and G&P. As of December 31, 2020, our assets and operations in each of these segments are described below.

L&S:

The L&S segment includes transportation, storage and marketing of crude oil, refined products and other hydrocarbon-based products. These assets consist of a network of wholly and jointly-owned common carrier crude oil and refined product pipelines and associated storage assets, terminals, storage caverns, tank farm assets including rail and truck racks, an inland marine business, an export terminal and a fuels distribution business. Our pipeline network includes pipelines throughout the continental United States and Alaska. Our storage caverns consist of butane, propane, and liquefied petroleum gas storage with locations in Neal, West Virginia; Woodhaven, Michigan; Robinson, Illinois; and Jal, New Mexico. Our terminal facilities for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products are also located throughout the continental United States and Alaska. We also own tank farm assets at certain MPC refineries in addition to stand-alone tank farms. Our network of terminals and refinery assets also includes rail and truck loading lanes/racks in addition to barge docks which support the transportation of hydrocarbon products via rail, over the road or marine. Our marine business owns and operates boats and barges, including third-party chartered equipment, and includes a Marine Repair Facility (“MRF”), which is a full-service marine shipyard located on the Ohio River adjacent to MPC’s Catlettsburg, Kentucky refinery. We also have ownership in various joint-interests, including LOOP LLC, the only U.S. deep-water oil port, located offshore of Louisiana, which is used to import and export crude oil. Our fuels distribution business provides MPC with a broad range of scheduling and marketing services. For additional information related to our L&S assets, please see Item 2. Properties - Logistics and Storage. Our L&S assets are integral to the success of MPC’s operations. We continue to evaluate projects and opportunities that will further enhance our existing operations and provide valuable services to MPC and third parties. The following table summarizes projects and expansions that are expected to be completed in upcoming years.
Projects
New or expanded capacity
Expected in-service of expansion capacity
Wink to Webster Pipeline-crude oil pipeline1,500 mbpd2021
Whistler Pipeline-natural gas pipeline2,000 MMcf/d2021
NGL Takeaway System-NGL pipeline150 mbpd2021

We generate revenue in the L&S segment primarily by charging tariffs for crude gathering, transporting crude oil, refined products and other hydrocarbon-based products through our pipelines and at our barge docks delivering to domestic and international destinations, and fees for storing crude oil and refined products at our storage facilities. Our marine business generates revenue under a fee-for-capacity contract
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with MPC. Our fuels distribution business provides services related to the scheduling and marketing of products on behalf of MPC, for which it generates revenue based on the volume of MPC’s products sold each month. Up to July 31, 2020, our wholesale business included the operations of several bulk petroleum distribution plants and a fleet of refined product delivery trucks that distribute commercial wholesale petroleum products. On July 31, 2020, this business was transferred to MPC through the Wholesale Exchange. We are also the operator of additional crude oil and refined product pipelines owned by MPC and third parties for which we are paid operating fees. For the year ended December 31, 2020, approximately 92 percent of L&S segment revenues was generated from MPC.

G&P:

We operate several natural gas gathering systems with the scope of gathering services that we provide dependent upon the producers’ need and the composition of the raw or untreated gas at our producer customers’ wellheads. For dry gas, we gather and, if necessary, treat the gas and deliver it to downstream transmission systems. For wet gas that contains heavier and more valuable hydrocarbons, we gather the gas for processing at a processing complex. Our natural gas processing complexes remove the heavier and more valuable hydrocarbon components from natural gas. This allows the residue gas remaining after extraction of the NGLs to meet the quality specifications for long-haul pipeline transportation or commercial use. The capacities of our gathering systems and processing complexes are supported by long-term, fee-based agreements with certain major producers and a number of these agreements include acreage dedications. Once natural gas has been processed at a natural gas processing complex, the heavier and more valuable hydrocarbon components, which have been extracted as a mixed NGL stream, can be further separated into their component parts through the process of fractionation. Our NGL fractionation facilities separate the mixture of extracted NGLs into individual purity product components for end-use sale. Our fractionation facilities for propane and heavier NGLs are also supported by long-term, fee-based agreements with certain major producers.
As a result of natural gas production, we recover ethane from the natural gas stream for certain producer customers, which allows them to meet residue gas pipeline quality specifications and downstream pipeline commitments. Depending on market conditions, producer customers may also benefit from the potential price uplift received from the sale of their ethane. We have connections to several downstream ethane pipelines from many of our systems that benefit our customers.

As production in geographic regions and market demand continues to evolve, so do our planned capital expenditures. The following table summarizes our properties that are expected to be constructed or have planned expansions in upcoming years. As of December 31, 2020, our gathering and processing assets include approximately 9.2 Bcf/d of gathering capacity, 11.8 Bcf/d of natural gas processing capacity and 911 mbpd of fractionation and stabilization capacity. For a summary of our gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines see Item 2. Properties - Gathering and Processing. The following table summarizes projects and expansions that are expected to be completed in upcoming years.
Plant
Existing capacity
New or expanded capacity
Expected in-service of expansion capacity
Geographic Region
Processing (MMcf/d):
Smithburg 1 Processing Plant(1)
— 200 2021Marcellus Operations
Preakness Processing Plant— 200 2022Southwest Operations
(1)    This is a Sherwood Midstream LLC (“Sherwood Midstream”) investment.

A significant portion of our business comes from a limited number of key customers. For the year ended December 31, 2020, revenues earned from two customers are significant to the segment, each accounting for approximately 17 percent of G&P operating revenues and seven percent of consolidated operating revenues, respectively.

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The following table summarizes our key producer customers and attributes for each geographic region:
RegionKey Producer CustomersVolume Protection
Marcellus Operations(2)
Antero Resources,(1) Range Resources, Penn Energy, Southwestern,(1) EQT,(1) CNX, Equinor, HG Energy and others
74% of 2020 capacity contains minimum volume commitments
Utica Operations(2)
Ascent, Gulfport, Antero Resources(1) and others
27% of 2020 capacity contains minimum volume commitments
Southern Appalachia Operations
Diversified Gas & Oil(1) and others
24% of 2020 capacity contains minimum volume commitments
Southwest Operations(2)
Ovintiv Mid-Continent Inc, WSGP Gas Producing LLC, Chevron USA, Cimarex Energy Co. and others4% of 2020 capacity contains minimum volume commitments
Bakken Operations(2)
Whiting Oil and Gas Corporation(1) and others
N/A
Rockies Operations(2)
Pinedale Energy Partners,(1) EOG Resources Inc,(1) XTO Energy Inc, (1) and others
33% of 2020 capacity contains minimum volume commitments
(1)    We do not provide gathering services for these producer customers.
(2)    Region includes some contracts which contain acreage dedications.

For further financial information regarding our segments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Annual Report on Form 10-K.

OUR L&S CONTRACTS WITH MPC AND THIRD PARTIES

Transportation Services Agreements, Storage Services Agreements, Terminal Services Agreements and Fuels Distribution Services Agreement with MPC

Our L&S assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple transportation, terminal and storage services agreements with MPC. Under these long-term, fee-based agreements, we provide transportation, terminal and storage services to MPC and, other than under our marine transportation services agreement, most of these agreements include minimum committed volumes from MPC. MPC has also committed to pay a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation services agreement. We also have a fuels distribution agreement with MPC under which we provide scheduling and other services of MPC’s products.

The following table sets forth additional information regarding our transportation, terminal, fuels distribution, and storage services agreements with MPC:
AgreementInitiation Date
Term (years)(1)
MPC minimum
 commitment(2)
Transportation Services (mbpd):
Crude pipelinesVarious0-122,118 
Refined product pipelinesVarious1-151,799 
MarineJanuary 20156
N/A(3)
Storage Services (mbbls):
CavernsVarious10-174,375 
Tank Farms(4)
Various3-10129,268 
Terminal Services(5)
VariousVarious205,759 
Fuels Distribution Services (million gallons)February 20181023,449 
(1)    Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, year-to-year or one to two additional five-year terms for our terminal services agreements, various renewal terms ranging from zero to 10 years for our cavern storage services agreements, various renewal terms ranging from year-to-year to multiple additional five-year terms for our tank farm storage services agreements, two additional five-year terms for our marine transportation services agreement and one additional five-year term for our Fuels Distribution Services Agreement. These renewals are automatic, unless terminated by either party.
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(2)    Commitments for our transportation services agreements refer to throughput in thousands of barrels per day and, for crude oil transportation services agreements, are adjusted for crude viscosities. Commitments for our cavern storage services agreements refer to thousands of barrels. Commitments for our terminal services agreements refer to quarterly terminal throughput or stipulated volumes in thousands of barrels. Commitments for the fuels distribution services agreements refers to millions of gallons per year. Minimum commitments on some agreements are reduced by any third-party throughput volumes.
(3)    MPC has committed to utilize 100 percent of our available capacity of boats and barges.
(4)    Volume shown represents total shell capacity in thousands of barrels (includes refining logistics tanks).
(5)    Some terminal services agreements also contain minimum commitments for activities such as blending, additives, on-loading and off-loading, and storage.

Under transportation services agreements containing minimum volume commitments, if MPC fails to transport its minimum throughput volumes during any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. Under these transportation services agreements, the amount of any deficiency payment paid by MPC may be applied as a credit for any volumes transported on the applicable pipeline in excess of MPC’s minimum volume commitment during a limited number of succeeding periods, after which time any unused credits will expire.

We have crude oil and asphalt trucking transportation services agreements with MPC. Under these trucking transportation services agreements, we receive a service fee per barrel for gathering barrels and providing trucking, dispatch, delivery and data services.

Under most of our terminal services agreements, if MPC fails to meet its minimum volume commitment during any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. Some of our terminal services agreements contain minimum commitments for various additional services such as storage and blending.

We have a fuels distribution service agreement with MPC in which MPC pays MPLX a tiered monthly fee based on the volume of MPC’s products sold by MPLX each month, subject to a maximum annual volume. MPLX has agreed to use commercially reasonable efforts to sell not less than a minimum quarterly volume of MPC’s products during each calendar quarter. If MPLX sells less than the minimum quarterly volume of MPC’s products during any calendar quarter despite its commercially reasonable efforts, MPC will pay MPLX a deficiency payment equal to the volume deficiency multiplied by the applicable tiered fee. The dollar amount of actual sales volume of MPC’s products that exceeds the minimum quarterly volume (an “Excess Sale”) for a particular quarter will be applied as a credit, on a first-in-first-out basis, against any future deficiency payment owed by MPC to MPLX during the four calendar quarters immediately following the calendar quarter in which the Excess Sale occurs.

Pipeline Operating Agreements with MPC

We operate various pipelines owned by MPC under operating services agreements. Under these operating services agreements, we receive an operating fee for operating the assets, which include certain MPC wholly owned or partially owned crude oil, natural gas, and refined product pipelines, and for providing various operational services with respect to those assets. We are generally reimbursed for all direct and indirect costs associated with operating the assets and providing such operational services. These agreements vary in length and automatically renew with most agreements being indexed for inflation.

Pipeline Operating Agreements with Third Parties

We maintain and operate six pipelines through our joint interests in Andeavor Logistics Rio Pipeline LLC, BANGL LLC, Capline Pipeline Company LLC, Centennial Pipeline LLC, Louisville-Lexington Operation and Muskegon Pipeline LLC. We receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline. The length and renewal terms for each agreement vary.

Transportation and Terminal Services Agreements with Third Parties

We have multiple transportation and terminal services agreements with third parties under which we provide use of pipelines and tank storage, and provide services, facilities and other infrastructure related to the receipt, storage, throughput, blending and delivery of commodities. Some of these agreements are subject to prepaid throughput volumes under which we agree to handle a certain amount of product throughput each month in exchange for a predetermined fixed fee, with any excess throughput or ancillary
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services subject to additional charges. Under the remaining agreements we receive an agreed upon fee based on actual product throughput following the completion of services.

Marine Services Agreements with MPC

MPLX has a management services agreement and a loss control agreement with MPC under which it provides management and loss control services to assist MPC in the oversight and management of the marine business. MPLX receives fixed annual fees for providing the required services, which are subject to predetermined annual escalation rates. These agreements are subject to an initial terms of five years and automatically renew for one additional five-year renewal period unless terminated by either party.

Other Agreements with MPC

We have omnibus agreements with MPC that address our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain services to us, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we indemnify MPC for certain matters under these agreements.
We also have various employee services agreements and a secondment agreement under which we reimburse MPC for the provision of certain operational and management services to us. All of the employees that conduct our business are directly employed by affiliates of our general partner.

Additionally, we have certain indemnification agreements with MPC under which MPC retains responsibility for remediation of known environmental liabilities due to the use or operation of the assets prior to our ownership, and indemnifies us for any losses we incurred arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is generally limited to five years.

OUR G&P CONTRACTS WITH MPC AND THIRD PARTIES

The majority of our revenues in the G&P segment are generated from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. MPLX enters into a variety of contract types including fee-based, percent-of-proceeds, keep-whole and purchase arrangements in order to generate service revenue and product sales. See Item 8. Financial Statements and Supplementary Data - Note 2 for a further description of these different types of arrangements.

In many cases, MPLX provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of MPLX’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. In addition, minimum volume commitments may create contract liabilities or deferred credits if current period payments can be used for future services. These are recognized into service revenue in instances where it is probable the customer will not use the credit in future periods.

MPLX’s contract mix and exposure to natural gas and NGL prices may change as a result of changes in producer preferences, MPLX expansion in regions where some types of contracts are more common and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.

Keep-whole agreement with MPC

MPLX has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGLs related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provides for a base volume subject to a base rate and incremental volumes subject to variable rates, which are calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes are subject to revision each year.

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COMPETITION

Within our L&S segment, our competition primarily comes from independent terminal and pipeline companies, integrated petroleum companies, refining and marketing companies, distribution companies with marketing and trading arms and from other wholesale petroleum products distributors. Competition in any particular geographic area is affected significantly by the volume of products produced by refineries in the area, and in areas where no refinery is present, by the availability of products and the cost of transportation to the area from other locations.

As a result of our contractual relationship with MPC under our transportation and storage services agreements, our terminal services agreement, and our physical asset connections to MPC’s refineries and terminals, we believe that MPC will continue to utilize our assets for transportation, storage, distribution and marketing services. If MPC’s customers reduced their purchases of refined products from MPC due to increased availability of less expensive refined product from other suppliers or for other reasons, MPC may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which could decrease our revenues.

In our G&P segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering, transportation and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability, residue gas and NGL market connectivity, the ability to obtain a satisfactory price for products recovered and the fees charged for services supplied to the customer. Competition for oil supplies is based primarily on the price and scope of services, location of gathering/transportation and storage facilities and connectivity to the best priced markets. Competitive factors affecting our fractionation services include availability of fractionation capacity, proximity to supply and industry marketing centers, the fees charged for fractionation services and operating efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, credit and market connectivity.

Our competitors include:

natural gas midstream providers, of varying financial resources and experience, that gather, transport, process, fractionate, store and market natural gas and NGLs;
major integrated oil companies and refineries;
independent exploration and production companies;
interstate and intrastate pipelines; and
other marine and land-based transporters of natural gas and NGLs.

Some of our competitors operate as MLPs or are owned by infrastructure funds and may enjoy a cost of capital comparable to and, in some cases, lower than ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.

We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements, allows us to compete more effectively. This includes having access to both NGL and natural gas markets to allow for flexibility in our gathering and processing in addition to having critical connections to a strong sponsor and key market outlets for NGLs and natural gas. Our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of our resource plays. The strategic location of our assets, including those connected to MPC, and the long-term nature of many of our contracts also provide a significant competitive advantage.

INSURANCE

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and business interruption. We are insured under MPC and other third-party insurance policies. The MPC policies are subject to shared deductibles.
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SEASONALITY

The volume of crude oil and refined products transported and stored utilizing our assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Any effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments.

In our G&P segment we experience minimal impacts from seasonal fluctuations which impact the demand for natural gas and NGLs and the related commodity prices caused by various factors including variations in weather patterns from year to year. We are able to manage the seasonality impacts through the execution of our marketing strategy and via our storage capabilities. Overall, our exposure to the seasonality fluctuations is declining due to our growth in fee-based business.

REGULATORY MATTERS

Our operations are subject to numerous laws and regulations, including those relating to the protection of the environment. Such laws and regulations include, among others, the Interstate Commerce Act (“ICA”), the Natural Gas Act (“NGA”), the Clean Water Act (“CWA”) with respect to water discharges, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. New laws are being enacted and regulations are being adopted on a continuing basis, and the costs of compliance with such new laws and regulations are very difficult to estimate until finalized.

For a discussion of environmental capital expenditures and costs of compliance, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Environmental Matters and Compliance Costs. For additional information regarding regulatory risks, see Item 1A. Risk Factors.

Pipeline Regulations

Common Carrier Liquids Pipeline Operations

We have liquids pipelines that are common carriers subject to regulation by various federal, state and local agencies. FERC regulates interstate transportation on liquids pipelines under the ICA, Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that tariff rates for interstate pipelines that transport crude oil, NGLs (including purity ethane) and refined petroleum products (collectively referred to as “petroleum pipelines”), be just and reasonable and the terms and conditions of service must not be unduly discriminatory or confer any undue preference upon any shipper.

The ICA requires that interstate petroleum pipeline transportation rates and terms and conditions of service be filed with the governing agency, which is FERC, and posted publicly. Under the ICA, persons with a substantial economic interest in a petroleum pipeline’s rate or service may challenge that rate or service before FERC. FERC is authorized to investigate such challenges and may suspend the effectiveness of a newly filed rate or term or condition of service for up to seven months. A successful protest to a new rate or term of condition of service could result in a petroleum pipeline paying refunds, together with interest, for the period that the rate or term or condition of service was in effect. A successful protest could also result in FERC disallowing the rate or service. A successful complaint to an existing rate or service could result in a petroleum pipeline paying refunds, together with interest, for the period beginning two years prior to the date of the filing of the complaint until the just and reasonable rate or service was established. FERC may also investigate, upon complaint, protest, or on its own motion, newly proposed rates and terms of service, existing rates and related rules, and may order a pipeline to change them prospectively or may bar a pipeline from implementing the proposed new or changed rates or terms of service.

EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Our rates for interstate transportation service in effect for the 365-day period ending on the date of the passage of EPAct 1992
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were deemed just and reasonable and therefore are grandfathered. Subsequent changes to those rates are not grandfathered. New rates have since been established after EPAct 1992 for certain pipelines, and the rates for certain of our refined products pipelines have subsequently been approved as market-based rates.

EPAct 1992 required FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, FERC adopted an indexed rate methodology which, as currently in effect, allows petroleum pipelines to change their rates within prescribed ceiling levels that are tied to annual changes in the producer price index-finished goods (“PPI-FG”). FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by the change in the PPI-FG plus an adder that is currently set at 1.23 percent. The current adder will be in effect until June 30, 2021 or until revised by a formal rulemaking by FERC. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates and settlement rates (unless permitted under the settlement). A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s costs. However, FERC is currently evaluating how indexed adjustments to rates can be challenged as well as how pipelines must demonstrate their annual costs and incomes. Therefore, we cannot guarantee FERC will not make changes to its current policy regarding challenges in the future. Under the indexing rate methodology, in any year in which the index is negative, a pipeline must lower the rate ceiling and file to lower rates if any of the pipelines’ rates would otherwise be above the new rate ceiling, unless the pipeline makes a filing attesting that all shippers that pay the rate have approved the pipeline not lowering the rate or the pipeline can demonstrate substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index.

While petroleum pipelines often use the indexing methodology to change their rates, petroleum pipelines may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. At various times, we have used index rates, settlement rates and market-based rates to change the rates for our different FERC-regulated petroleum pipelines.

Intrastate services provided by certain of our liquids pipelines are subject to regulation by state regulatory authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. Not all state regulatory bodies allow for changes based on an index method similar to that used by FERC. In those instances, rates are generally changed only through a rate case process. The state regulators could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could, if permitted under state law, require the payment of refunds to shippers.

FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates are not the subject of a protest or a complaint by a shipper. FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in our tariff rate level.

Our liquids pipelines are also subject to safety regulation by the DOT under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines. In October 2019, PHMSA finalized rulemaking reviewing the scope and applicability of 49 C.F.R. Part 195, including, among other things, expansion of reporting obligations, additional inspection requirements, emergency order authority, expansion of integrity management principles and expansion of the use of leak detection systems. These changes became effective in 2020 and could have an impact upon MPLX LP and other pipeline operators. Our liquids pipelines and operations may also be or become subject to state public utility or related jurisdiction, which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of liquids gathering facilities.

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FERC-Regulated Natural Gas Pipelines

Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable, or unduly discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. The rates and terms and conditions for the Hobbs Pipeline and the Arkoma Connector Pipeline can be found in their respective FERC-approved tariffs and in negotiated rate agreements entered into under those tariffs. Rendezvous Pipeline Company has authority to charge market-based rates, and its tariffs and pertinent operational information can be found on its website. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases proposed by the pipeline or other tariff changes may be challenged (e.g., by protest). We also cannot be assured that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules, rights of access, capacity and other issues that impact natural gas facilities. Any successful complaint or protest related to our services or facilities could have an adverse impact on our revenues.

Energy Policy Act of 2005

Under the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”), FERC may impose civil penalties for violations of statutory and regulatory requirements. The 2005 EPAct also amends the NGA to add an anti-market manipulation provision, which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. FERC issued Order No. 670 to implement the anti-market manipulation provision of the 2005 EPAct. This order makes it unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, use or employ any device, scheme or artifice to defraud in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person.

Standards of Conduct

FERC has adopted affiliate standards of conduct applicable to interstate natural gas pipelines and certain other regulated entities, defined as “Transmission Providers.” Under these rules, a Transmission Provider becomes subject to the standards of conduct if it provides service to affiliates that engage in marketing functions (as defined in the standards). If a Transmission Provider is subject to the standards of conduct, the Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). The Transmission Provider must also comply with certain posting and other requirements.

Intrastate Natural Gas Pipeline Regulation

Some of our intrastate gas pipeline facilities are subject to various state laws and regulations that affect the rates we charge and terms of service. Although state regulation is typically less onerous than FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC’s jurisdiction. We are subject to such regulations and reporting requirements to the extent that any of our intrastate pipelines provide, or are found to provide, such interstate services.

Additional proposals and proceedings that might affect the natural gas industry periodically arise before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory
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changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than other midstream natural gas companies with whom we compete.

Natural Gas Gathering Pipeline Regulation

Section 1(b) of the NGA exempts natural gas production and gathering from the jurisdiction of FERC. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Rather, FERC looks at a number of factors, including length and diameter of pipeline facilities, extension beyond the central point of the field, geographic configuration, location of compressors and processing plants, location of wells along all or part of the facility and operating pressure of the facilities. We own a number of facilities that we believe qualify as production and gathering facilities not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, potentially provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC reporting requirements.

In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, non-discriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

On January 11, 2021, PHMSA published a Final Rule amending the gas pipeline safety regulations at 49 C.F.R. Parts 191 and 192. The effective date of the Final rule is March 12, 2021, with a deferred compliance date of October 1, 2021 for the new amendments. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated companies.

Natural Gas Processing

Our natural gas processing operations are not presently subject to FERC or state rate regulation. There can be no assurance that our processing operations will continue to be exempt from rate regulation in the future. In addition, although the processing facilities may not be directly related, other laws and regulations may affect the availability of natural gas for processing, such as state regulation of production rates and maximum daily production allowances from gas wells, which could impact our processing business.

NGL Pipelines

We have constructed various NGL product pipelines to transport NGL products, some of which are regulated by FERC, and we may elect to construct additional such pipelines in the future that may be subject to these same regulatory requirements. Pipelines providing transportation of NGLs in interstate commerce are subject to the same regulatory requirements as common carrier petroleum pipelines. See “Common Carrier Liquids Pipeline Operations” above.
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Our NGL pipelines are also subject to safety regulation by the DOT under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines. In October 2019, PHMSA finalized rulemaking reviewing the scope and applicability of 49 C.F.R. Part 195, including, among other things, expansion of reporting obligations, additional inspection requirements, emergency order authority, expansion of integrity management principles and expansion of the use of leak detection systems. These changes became effective in 2020 and could have an impact upon MPLX LP and other pipeline operators. Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.

Marine Transportation

Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act, state laws and certain international conventions, as well as numerous environmental regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels.

Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage law that restricts domestic marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones Act for our vessels. The loss of Jones Act status could have a significant negative effect on our marine transportation business. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the USCG, and the application of United States labor and tax laws increases the cost of United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that is not subject to the same United States government imposed burdens.

The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is necessary in the interest of national defense. For example, the Secretary has waived the Jones Act generally or with respect to the transportation of certain petroleum products for limited periods of time and in limited areas following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act, whether in response to natural disasters or otherwise, could result in increased competition from foreign tank vessel operators, which could negatively impact our marine transportation business.

Security

Certain of our facilities have been preliminarily classified as subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” The Transportation Security Administration Security Guidelines are subject to change without formal regulatory proposal and review. We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

ENVIRONMENTAL REGULATION

We believe it is likely that the scientific and political attention to greenhouse gas emissions, climate change and climate adaptation will continue, with the potential for further regulations that could affect our operations. Currently, legislative and regulatory measures to address greenhouse gas emissions are in various phases of review, discussion or implementation. Reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities, (iii) capture the emissions from our facilities and (iv) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments.

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General

Our processing and fractionation plants, storage facilities, pipelines and associated facilities are subject to multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and regulations relating to environmental protection. Such environmental laws and regulations may affect many aspects of our present and future operations, including for example, requiring the acquisition of permits or other approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays, restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other activities in environmentally sensitive areas such as wetlands or areas inhabited by threatened or endangered species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution that might be caused by our operations or attributable to former operations. Spills, releases or other incidents may occur in connection with our active operations or as a result of events outside of our reasonable control, which incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of remedial or corrective actions and the issuance of orders enjoining or limiting some or all of our operations.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and the cost of continued compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition. We cannot assure, however, that existing environmental laws and regulations will not be reinterpreted or revised or that new environmental laws and regulations will not be adopted or become applicable to us. Generally speaking, the trend in environmental law is to place more restrictions and limitations on activities that may be perceived to adversely affect the environment, which may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our permitting applications, or cause us to become involved in time consuming and costly litigation. Thus, there can be no assurance as to the amount or timing of future expenditures for compliance with environmental laws and regulations, permits and permitting requirements or remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements may result in increased compliance and mitigation costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, and could have a material adverse effect on our business, financial condition, results of operations and cash flow. We may not be able to recover some or any of these costs from insurance. Such revised or additional environmental requirements may also result in substantially increased costs and material delays in the construction of new facilities or expansion of our existing facilities, which may materially impact our ability to meet our construction obligations with our producer customers.

Remediation

A comprehensive framework of environmental laws and regulations governs our operations as they relate to the possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and surface water and measures taken to mitigate pollution into the environment. CERCLA, also known as the “Superfund” law, as well as comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment and for restoration costs and damages to natural resources. RCRA and similar state laws may also impose liability for removing or remediating releases of hazardous or non-hazardous wastes from impacted properties.

We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering, processing and transportation, for NGL fractionation, for the storage, gathering and transportation of crude oil, or for the storage and transportation of refined products. During the normal course of operation, whether by us or prior owners or operators, releases of petroleum hydrocarbons or other non-hazardous or hazardous wastes have or may have occurred. We could be required to remove or remediate previously disposed wastes or property contamination, including
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groundwater contamination, or to perform remedial operations to prevent future contamination. We do not believe that we have any current material liability for cleanup costs under such laws or for third-party claims.

Hazardous and Solid Wastes

We may incur liability under RCRA, and comparable or more stringent state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous wastes. In the course of our operations, we generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. It is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and disposal requirements.

Water

We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. In addition, we are regulated under OPA-90, which, among other things, requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. OPA-90 also requires the responsible company to pay resulting removal costs and damages and provides for civil penalties and criminal sanctions for violations of its provisions. We operate tank vessels and facilities from which spills of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures plans for all facilities subject to such requirements. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.

Construction or maintenance of our plants, compressor stations, pipelines, barge dock and storage facilities may impact wetlands or other surface water bodies, which are also regulated under the CWA by the EPA, the United States Army Corps of Engineers and state water quality agencies. Regulatory requirements governing wetlands and other surface water bodies (including associated mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the CWA and analogous state laws. However, there is no assurance that we will not incur material increases in our operating costs or delays in the construction or expansion of our facilities because of future developments, the implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other causes.

In April 2020, the U.S. District Court in Montana vacated Nationwide Permit 12 (“NWP 12”), which authorizes the placement of fill material in “waters of the United States” for utility line activities as long as certain best management practices are implemented. The decision was ultimately appealed to the United States Supreme Court, which partially reversed the district court’s decision, temporarily reinstating NWP 12 for all projects except the Keystone XL oil pipeline. The United States Army Corps of Engineers subsequently reissued its nationwide permit authorizations on January 13, 2021, by dividing the NWP that authorizes utility line activities (NWP 12) into three separate NWPs that address the differences in how different utility line projects are constructed, the substances they convey, and the different standards and best management practices that help ensure those NWPs authorize only those activities that have no more than minimal adverse environmental effects. The 2021 authorization may be challenged in court or the Biden Administration may repeal or replace the 2021 authorization in a subsequent rulemaking. Repeal or replacement of the rule could impact pipeline maintenance activities.

Air Emissions

The Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or
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significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions, or aggregate two or more of our facilities into one application for permitting purposes. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements. However, we may be required to incur capital expenditures in the future for installation of air pollution control equipment and encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of new or amended permits, and we may be required to modify certain of our operations which could increase our operating costs.

In 2015, the EPA finalized a revision to the National Ambient Air Quality Standards (“NAAQS”) for ozone. The EPA lowered the primary ozone NAAQS from 75 parts per billion to 70 parts per billion. In December 2020, the EPA published a rule maintaining this standard. Designation as a nonattainment area could result in increased costs associated with, or result in cancellation or delay of, capital projects at our or our customers’ facilities, or could require nitrogen oxides and/or volatile organic compound reductions that could result in increased costs to us or our customers. We cannot predict the effects of the various state implementation plan requirements at this time.
Climate Change

As a consequence of an EPA administrative conclusion that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) into the ambient air endangers public health and welfare, the EPA adopted regulations establishing the Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Although the EPA’s PSD and Title V permit programs are limited to large stationary sources of criteria pollutant emissions, states may seek to adopt their own permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs. If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or if the EPA implemented more stringent permitting requirements relating to GHG emissions without regard to non-GHG criteria pollutants, or if states adopt their own permitting programs that require permit reviews based on GHG emissions, we may be required to install “best available control technology,” to the extent such technology is available, to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future. In addition, we may experience substantial delays or possible curtailment of construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating permits, we may encounter limitations on the design capacities or size of facilities, and we may incur material increases in our construction and operating costs. We are monitoring GHG emissions from certain of our facilities in accordance with current GHG emissions reporting requirements in a manner that we believe is in substantial compliance with applicable reporting obligations.

Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and it is possible that such legislation could be enacted in the future. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. In 2020, the EPA rescinded regulation of methane emissions from the oil and gas industry as originally adopted in the EPA’s 2016 New Source Performance Standards (“NSPS”), which were aimed at minimizing fugitive emissions and establishing methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. The EPA’s rescission of the methane emission regulations is being challenged in court. Further, President Biden’s Executive Order on climate change calls for the federal government to reduce methane emissions from the oil and gas industry as quickly as possible. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas produced by our exploration and production customers that, in turn, could reduce the demand for our services and thus adversely affect our cash available for distribution to our unitholders.

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Under the National Environmental Policy Act, environmental assessments must be performed for certain projects, including construction of certain new pipelines. On July 16, 2020, the Council on Environmental Quality published a rule updating the regulations implementing the procedural provisions of the National Environmental Policy Act. This update rule sought to modernize and clarify environmental assessment requirements. This rule is being challenged in court and could be revisited by the new administration. It is uncertain the extent to which an environmental assessment must consider direct and indirect greenhouse gas emissions from a new project. This uncertainty can result in delay and increased costs in completing new projects.

Endangered Species Act and Migratory Bird Treaty Act Considerations

The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that may affect endangered or threatened species, including their habitats. If protected species are located in areas where we propose to construct new gathering or transportation pipelines, processing or fractionation facilities, or other infrastructure, such work could be prohibited or delayed in certain of those locations or during certain times, when our operations could result in a taking of the species or destroy or adversely modify critical habitat that has been designated for the species. We also may be obligated to develop plans to avoid potential takings of protected species and provide mitigation to offset the effects of any unavoidable impacts, the implementation of which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increases our construction and mitigation costs or restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to a listed species and could result in alleged takings under the ESA, exposing MPLX to civil or criminal enforcement actions and fines or penalties. The existence of threatened or endangered species in areas where we conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from species protection measures or could result in delays in, or prohibit, the construction of our facilities or limit our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.

The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without authorization. If there is the potential to adversely affect migratory birds as a result of our operations or construction activities, we may be required to seek authorization to conduct those operations or construction activities, which may result in specified operating or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an adverse impact on our ability to provide timely gathering, processing or fractionation services to our exploration and production customers.

Safety Matters

We are subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended, as well as comparable state statutes that regulate the protection of the health and safety of workers. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

We are also subject at regulated facilities to the OSHA’s Process Safety Management and EPA’s Risk Management Program requirements, which are intended to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The application of these regulations can result in increased compliance expenditures.

In general, we expect industry and regulatory safety standards to become stricter over time, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

The DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline
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operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans. These regulations are discussed more fully below.

PHMSA Regulation

We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979, also known as the HLPSA. The HLPSA delegated to the DOT the authority to develop, prescribe and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, also known as the PSA, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in High Consequence Areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, also known as the APSPA, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, also known as the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. We are also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. Additionally, we are subject to the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which required PHMSA to develop underground gas storage standards within two years and provided PHMSA with significant new authority to issue industry-wide emergency orders if an unsafe condition or practices results in an imminent hazard.

The DOT has delegated its authority under these statutes to the PHMSA, which administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of natural gas by pipeline (49 C.F.R. Part 192), as well as hazardous liquids by pipeline (49 C.F.R. Part 195), including regulations for the design and construction of new pipelines or those that have been relocated, replaced or otherwise changed (Subparts C and D of 49 C.F.R., Part 195); pressure testing of new pipelines (Subpart E of 49 C.F.R. Part 195); operation and maintenance of pipelines, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs and managing the operation of pipeline control rooms (Subpart F of 49 C.F.R. Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 C.F.R. Part 195); and integrity management requirements for pipelines in HCAs (49 C.F.R. 195.452). PHMSA has undertaken a number of initiatives to reevaluate its pipeline safety regulations. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.

Notwithstanding the foregoing, PHMSA and one or more state regulators have, in isolated circumstances in the past, sought to expand the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities in order to assess compliance with hazardous liquids pipeline safety requirements. If any of these actions were made broadly enforceable as part of a rule-making process or codified into law, they could result in additional capital costs, possible operational delays and increased costs of operation.

Product Quality Standards

Refined products and other hydrocarbon-based products that we transport are generally sold by us or our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality specifications for products. The EPA established sulfur specifications for natural gasoline sold as certified ethanol denaturant effective January 1, 2017. The EPA has proposed product quality specifications for natural gasoline used for blendstock in ethanol flex fuel. The EPA has also
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established product quality specifications related to blending gasoline with blendstocks and ethanol, which we perform at certain of our light products storage facilities. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the products in our system and could require the construction of additional storage. In addition, changes in the product quality of the products we receive on our product pipelines could reduce or eliminate our ability to blend products.

Tribal Lands

Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. In addition, each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our operations on such lands.

HUMAN CAPITAL

We are managed and operated by the board of directors and executive officers of MPLX GP LLC (“MPLX GP”), our general partner. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are directly employed by affiliates of our general partner. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

MPC believes its employees are its greatest source of strength, and the culture reflects the quality of individuals across its workforce. Its collaborative efforts to foster an inclusive environment, provide broad-based development and mentorship opportunities, recognize and reward accomplishments, and offer benefits that support the well-being of its employees and their families contribute to increased engagement and fulfilling careers. Empowering people and prioritizing accountability also are key components for developing a high-performing culture, which is critical to achieving our strategic vision.

Employee Profile

As of December 31, 2020, MPC had approximately 57,900 regular full-time and part-time roles. Excluding employees of Speedway, which is targeted to be sold in the first quarter of 2021, MPC employs approximately 18,600 people in full-time and part-time roles. Our general partner and its affiliates have approximately 5,700 full-time employees that provide services to us under our employee services agreements.

Talent Management

Executing MPC’s strategic vision requires that it attracts and retains the best talent. Recruiting and retention success requires that it effectively nurtures new employees, providing opportunities for long-term engagement and career advancement. MPC also must appropriately reward high-performers and offer competitive benefits. MPC’s Talent Acquisition team consists of three segments: Executive Recruiting, Experienced Recruiting and University Recruiting. The specialization within each group allows those groups to specifically address MPC’s broad range of current and future talent needs, as well as devote time and attention to candidates during the hiring process. MPC values diverse perspectives in the workforce, and accordingly seeks candidates with a variety of backgrounds and experience. MPC’s primary source of full-time, entry-level new hires is its intern/co-op program. Through its university recruiters, MPC offers college students who have completed their freshman year the opportunity to participate in its hands-on programs focused in areas of finance and accounting, marketing, engineering and IT.

MPC provides a broad range of leadership training opportunities to support the development of leaders at all levels. Those programs, which are offered across the organization are a blended approach of business and leadership content, with many featuring external faculty. MPC utilizes various learning modalities, such as visual, audio, print, tactile, interactive, kinesthetic, experiential and leader-teaching-leader to
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address and engage different learning styles. MPC believes networking and access to executives are key leadership success factors, and MPC incorporates these opportunities into all of its programs.

Compensation and Benefits

To ensure MPC is offering competitive pay packages in its recruitment and retention efforts, it annually benchmarks compensation, including base salaries, bonus levels and equity targets. MPC’s annual bonus program is a critical component of its compensation, as it provides individual rewards for achievement against preset financial and sustainability goals, encouraging a sense of employee ownership. Employees in officer-level pay grades, as well as senior leaders and most mid-level leaders, are eligible to receive long-term equity incentive awards as part of their compensation.

MPC offers comprehensive benefits, including medical, dental and vision insurance for employees, their spouses or domestic partners, and their dependents. MPC also provides retirement programs, life insurance, education assistance, family assistance, short-term disability and paid vacation and sick time. Following MPC’s acquisition of Andeavor, MPC enhanced several of its benefits programs. MPC increased the maximum accrual cap for vacation banks and doubled the number of college and trade school scholarships offered to the high school senior children of employees through the Marathon Petroleum Scholars Program. In addition, MPC increased its paid parental leave benefit to eight weeks for birth mothers and four weeks for nonbirth parents, including adoptive and foster parents. Both full-time and part-time employees are eligible for this benefit. Parents who both work for MPC or its affiliates are each eligible for a parental pay benefit.

Inclusion

MPC’s company-wide Diversity and Inclusion (“D&I”) program is managed by a dedicated D&I Office team and supported by leadership. The program is based on MPC’s three-pillar D&I strategy of building awareness, increasing representation and ensuring success. The strategy focuses on understanding the benefits of diverse perspectives, increasing diversity across the organization and recognizing that cultural inclusion is an ongoing process. MPC has employee networks focusing on six populations: Asian, Black, Hispanic, Veterans, Women and LGBTQ+. All networks encourage ally membership. This broad support extends also to leaders throughout MPC, with each employee network represented by two active executive sponsors. The sponsors form several counsels that meet regularly to share updates, gain alignment, build deeper connections across networks and pursue collaboration ideas. The employee networks not only provide opportunities for employees to make meaningful and supportive connections, but they also serve a significant role in MPC’s D&I strategy.

Safety

MPC is committed to safe operations to protect the health and safety of its employees, contractors and communities. MPC’s commitment to safe operations is reflected in its safety systems design, its well-maintained equipment and by learning from its incidents. Part of MPC’s effort to promote safety includes a management system based on the principles of RC14001®, the Plan-Do-Check-Act continual improvement cycle, and its Operational Excellence Management System. Together, these components of MPC’s safety management system provide it with a comprehensive approach to managing risks and preventing incidents, illnesses and fatalities. Additionally, MPC’s annual cash bonus program metrics includes several employee, process and environmental safety metrics.

The COVID-19 pandemic has underscored for MPC the importance of keeping its employees safe and healthy. In March 2020, MPC activated its Corporate Emergency Response Team to ensure a consistent and aggressive response across all facets of MPC and MPLX. The safety and health of employees, including essential personnel, were top priorities for MPC and MPLX. As part of MPC’s existing pandemic plan, MPC had a central inventory of N95 respirators, surgical masks, and nitrile gloves to supply to employees and contractors when the pandemic began. MPC implemented a number of protective measures to ensure employee and contractor safety as they continued to keep our critical operations running safely. MPC continues to monitor the situation and adapt its practices as appropriate.

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AVAILABLE INFORMATION

General information about MPLX LP and our general partner, MPLX GP LLC, including Governance Principles, Audit Committee Charter, Conflicts Committee Charter and Certificate of Limited Partnership, can be found at www.mplx.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available in this same location.

MPLX LP uses its website, www.mplx.com, as a channel for routine distribution of important information, including news releases, analyst presentations and financial information. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC, or on the SEC’s website at www.sec.gov. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

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Item 1A. Risk Factors

You should carefully consider each of the following risks and all the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. Our business, financial condition, results of operations and cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline.

Summary of Risk Factors

We have in the past been adversely affected by certain of, and may in the future be materially and adversely affected by, the following:

the COVID-19 pandemic;
a significant decrease in oil and natural gas production in our areas of operation;
challenges in accurately estimating expected production volumes of our producer customers;
our dependence on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities;
our ability to retain existing customers or acquire new customers;
our ability to increase fees enough to cover costs incurred under our gathering, processing, transmission, transportation, fractionation, stabilization and storage agreements;
unplanned maintenance of the United States (“U.S.”) inland waterway infrastructure;
interruptions in operations at any of our facilities or those of our customers, including MPC;
problems affecting our information technology systems;
in our joint ventures, our lack of sole decision-making authority, our reliance on our joint venture partners’ financial condition and disputes between us and our joint venture partners;
terrorist attacks aimed at our facilities or that impact our customers or the markets we serve;
increases to our maintenance or repair costs;
severe weather events and other climate conditions;
insufficient cash from operations after the establishment of cash reserves and payment of our expenses to enable us to pay the intended quarterly distribution to our unitholders;
our substantial debt and other financial obligations;
changes to our credit ratings;
increases in interest rates;
uncertainty relating to the calculation of LIBOR and replacement reference rates;
our exposure to the credit risks of our key customers and derivative counterparties;
negative effects of our commodity derivative activities;
uninsured losses;
future costs relating to evolving environmental or other laws or regulations;
increased regulation of hydraulic fracturing;
climate-related and greenhouse gas emission regulation;
societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels;
federal and tribal approvals, regulations and lawsuits relating to our facilities that are located on Native American tribal lands;
an indemnifying third party failing to fulfill its indemnification obligations to us;
our ability to maintain or obtain real property rights required for our business;
the consequences resulting from foreign investment in us or our general partner exceeding certain levels;
federal or state rate and service regulation or rate-making policies;
costs and liabilities resulting from performance of pipeline integrity programs and related repairs;
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the Court of Chancery of the State of Delaware being, to the extent permitted by law, the sole and exclusive forum for substantially all disputes between us and our limited partners;
future impairments;
difficulties in making strategic acquisitions on economically acceptable terms from MPC or third parties;
integration risks from significant future acquisitions;
the failure by MPC to satisfy its obligations to us, or a significant reduction in volumes transported through our facilities or stored at our storage assets;
MPC materially suspending, reducing or terminating its obligations under its agreements with us;
MPC’s level of indebtedness or credit ratings;
various tax risks inherent in our master limited partnership structure, including the potential for unexpected tax liabilities for us or our unitholders, more burdensome tax filing requirements and future legislative changes to the expected tax treatment of an investment in us;
MPC’s conflicts of interest with us, its limited duties to us and our unitholders, and its potential favoring of its interests over our interests and the interests of our unitholders;
the requirements and restrictions arising under our Partnership Agreement, including the requirement that we distribute all of our available cash, limitations on our general partner’s duties, limited unitholder voting rights, and limited unitholder recourse in the event unitholders are dissatisfied with our operations;
cost reimbursements and fees paid to our general partner and its affiliates, which in certain circumstances are subject to our general partner’s sole discretion;
control of our general partner being transferred to a third party without unitholder consent;
the issuance of additional units resulting in the dilution of limited unitholder interests, which issuances may be made without unitholder approval;
the sale of units - and the adverse impact on the trading price of the common units which might result from such sale - by MPC of the units it holds in public or private markets, and such sales could have an adverse impact on the trading price of the common units;
affiliates of our general partner, including MPC, competing with us, and neither our general partner nor its affiliates having any obligation to present business opportunities to us;
our general partner having a limited call right that may require unitholders to sell common units at an undesirable time or price;
a unitholder’s liability not being limited if a court finds that unitholder action constitutes control of our business;
unitholders may have to repay distributions that were wrongfully distributed to them;
the NYSE not requiring a publicly traded limited partnership like us to comply with certain of its corporate governance requirements; and
global economic conditions.

Business and Operational Risks

The COVID-19 pandemic resulted in a significant decrease in demand for the petroleum products that we transport and store, which has had, and may continue to have, a material and adverse effect on our and our customers’ business and on general economic, financial and business conditions.

The COVID-19 pandemic continues to negatively impact worldwide economic and commercial activity. Travel restrictions, business and school closures, increased remote work, stay-at-home orders and other actions taken by individuals, governments and the private sector to stem the spread of the virus have significantly reduced global economic activity, significantly reduced demand for the petroleum products that we transport and store, and contributed to increased market and oil price volatility.

Resurgences in COVID-19 infections could result in the imposition of new stay-at-home orders or other restrictions to slow the spread of the virus, which could further weaken demand for the petroleum products we transport and store, and could contribute to increased market and oil price volatility.

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A prolonged period of economic slowdown or recession, or a protracted period of depressed prices for crude oil or refined petroleum products, could have significant and adverse consequences for our financial condition and the financial condition of our customers, suppliers and other counterparties, and could diminish our liquidity or trigger additional impairments.

The ultimate extent to which the COVID-19 pandemic will continue to negatively affect us and our customers, suppliers and other counterparties will depend largely on the length and severity of the pandemic; actions taken by individuals, governments and the private sector to stem the spread of the virus; general economic conditions; and the availability, widespread distribution and use of safe and effective vaccines, all of which cannot be predicted with certainty.

A significant decrease in oil and natural gas production in our areas of operation may adversely affect our business, financial condition, results of operation and cash available for distribution.

A significant portion of our operations is dependent on the continued availability of natural gas and crude oil production. The production from oil and natural gas reserves and wells owned by our producer customers will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful drilling activity near our facilities, our ability to compete for volumes from successful new wells and our ability to expand our system capacity as needed.

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by demand, prevailing and projected energy prices, drilling costs, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Reductions in exploration or production activity in our areas of operations could lead to reduced throughput on our pipelines and utilization rates of our facilities.

Decreases in energy prices can decrease drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend upon factors beyond our control, including global and local demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices could result in producers deciding to limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGLs to our facilities and adversely affect our revenues and cash available for distribution.

This impact may also be exacerbated due to the extent of our commodity-based contracts, which are more directly impacted by changes in natural gas and NGL prices than our fee-based contracts due to frac spread exposure and may result in operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In addition, our purchase and resale of gas and NGLs in the ordinary course exposes us to significant risk of volatility in natural gas or NGL prices due to the potential difference in the time of the purchases and sales and the potential difference in the price associated with each transaction, and direct exposure may also occur naturally as a result of our production processes. The significant volatility in natural gas, NGL and oil prices could adversely impact our unit price, thereby increasing our distribution yield and cost of capital. Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy our obligations to our customers, and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.

We may not always be able to accurately estimate expected production volumes of our producer customers; therefore, volumes we service in the future could be less than we anticipate.

We may not be able to accurately estimate expected production volumes of our producer customers. Furthermore, we may have only limited oil, natural gas, NGL or refined product supplies committed to any new facility prior to its construction. We may construct facilities to capture anticipated future growth in production or satisfy anticipated market demand which does not materialize, the facilities may not operate as planned or may not be used at all. In order to attract additional oil, natural gas, NGL or refined product
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supplies from a customer, we may be required to order equipment and facilities, obtain rights of way or other land rights or otherwise commence construction activities for facilities that will be required to serve such customer’s additional supplies prior to executing agreements with the customer. If such agreements are not executed, we may be unable to recover such costs and expenses. Additionally, new facilities may not be able to attract enough oil, natural gas, NGLs or refined products to achieve our expected investment return. Alternatively, oil, natural gas, NGL or refined product supplies committed to facilities under construction may be delivered prior to completion of such facilities, or we may otherwise have unexpected increases in volumes that could adversely affect our ability to expand our facilities. In such event, we may be required to temporarily utilize third-party facilities for such oil, natural gas, NGLs or refined products, which may increase our operating costs and reduce our cash available for distribution.

We depend on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

A significant portion of our supply of oil, natural gas, refinery off-gas, NGLs and refined products comes from a limited number of key producers/suppliers, who may be under no obligation to deliver a specific volume to our facilities. If any of these significant suppliers, or a significant number of smaller producers, were to decrease the supply of oil, natural gas, refinery off-gas, NGLs or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural gas, refinery off-gas, NGLs or refined products to our facilities or we rely on other third parties to deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow.

We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.

A significant portion of our business comes from a limited number of key customers. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines and fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new customers that we cannot provide. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services.

As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability.
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The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events outside our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if third parties suspend or terminate their contracts with us, our financial results would suffer.

The U.S. inland waterway infrastructure is aging and planned and unplanned maintenance may adversely affect our operations.

Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by approximately 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the locks, planned and unplanned maintenance may create more frequent outages, resulting in delays and additional operating expenses. Part of the costs for new construction and major rehabilitation of locks and dams is funded by marine transportation companies through taxes and the other portion is funded by general federal tax revenues. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products to our customers on a timely basis. Furthermore, any additional user taxes that may be imposed in the future to fund infrastructure improvements would increase our operating expenses.

Our operations are subject to business interruptions and casualty losses, which could materially and adversely affect our operations, financial condition, results of operations and cash flows.

Our operations are subject to business interruptions, such as unplanned maintenance, explosions, fires, pipeline releases, power outages, severe weather, labor disputes, acts of terrorism or other natural or man-made disasters. The inability to operate one or more of our facilities due to any of these events could adversely affect us. Our customers’ operations, including MPC’s refining operations, are subject to similar risks.

Explosions, fires, pipeline releases, product quality or other incidents may result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. We and our customers have experienced certain of these incidents in the past. For assets located near populated areas, the level of damage resulting from these risks could be greater. Due to the nature of our operations, certain interruptions could impact operations in other regions.

Our marine transportation business, in particular, is subject to weather conditions. Adverse weather conditions such as high or low water on the inland waterway systems, fog and ice, tropical storms, hurricanes and tsunamis on both the inland waterway systems and throughout the U.S. coastal waters can impair the operating efficiencies of the marine fleet. Such adverse weather conditions can cause a delay, diversion or postponement of shipments of products and are beyond our control.

In addition, we operate in and adjacent to environmentally sensitive waters where tanker, pipeline, rail car and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Transportation and storage of crude oil, other feedstocks and refined products over and adjacent to water involves inherent risk and subjects us to the provisions of the OPA-90 and state laws in U.S. coastal and Great Lakes states and states bordering inland waterways on which we operate. If we are unable to promptly and adequately contain any accident or discharge involving tankers, pipelines, rail cars or above ground storage tanks transporting or storing crude oil, other feedstocks or refined products, we may be subject to substantial liability. In addition, the service
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providers contracted to aid us in a discharge response may be unavailable due to weather conditions, governmental regulations or other local or global events.

The construction and operation of certain of our facilities may be impacted by surface or subsurface mining operations by one or more third parties, which could adversely impact our construction activities or cause subsidence or other damage to our facilities. In such event, our construction may be prevented or delayed, or the costs and time increased, or our operations at such facilities may be impaired or interrupted, and we may not be able to recover the costs incurred for delays or to relocate or repair our facilities from such third parties.

We rely on the performance of our information technology systems, and the interruption or failure of any information technology system, including an interruption or failure due to a cybersecurity breach, could have an adverse effect on our business, financial condition, results of operations and cash flows.

We are heavily dependent on our information technology systems (and those of our third-party business partners, whether cloud-based or hosted on proprietary servers), including our network infrastructure and cloud applications, for the safe and effective operation of our business. We rely on such systems to process, transmit and store electronic information, including financial records and personally identifiable information such as contractor, customer and investor data, and to manage or support a variety of business processes, including our pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions. Our systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, malware, power failures, cyber-attacks and other events. We also face various other cybersecurity threats from criminal hackers and employee malfeasance, including threats to gain unauthorized access to our computer network and systems or render data or systems unusable.

Our cybersecurity protections, infrastructure protection technologies, disaster recovery plans and employee training may not be sufficient to defend us against all unauthorized attempts to access our information. We have been and may in the future be subject to attempts to gain unauthorized access to our computer network and systems. To date, the impacts of prior events have not had a material adverse effect on us.

Any cybersecurity incident involving our information technology systems or those of our third-party business partners could result in theft, destruction, loss, misappropriation or release of confidential financial and other data or intellectual property; give rise to remediation or other expense; expose us to liability under federal and state laws; reduce our customers’ willingness to do business with us; disrupt the services we provide to customers; and subject us to litigation and legal liability under federal and state laws. Any of such results could have a material and adverse effect on our reputation, business, financial condition, results of operations and cash flows available for distribution to our unitholders.

Our investments in joint ventures could be adversely affected by our reliance on our joint venture partners and their financial condition, and our joint venture partners may have interests or goals that are inconsistent with ours.

We conduct some of our operations through joint ventures in which we share control over certain economic and business interests with our joint venture partners. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their obligations. Failure by us, or an entity in which we have an interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and adversely affect our reputation, business, financial condition, results of operations and cash flows.

Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.

Refining, gathering and processing, pipeline and terminal infrastructure, and other energy assets, may be future targets of terrorist organizations. Any terrorist attack on our facilities, those of our customers and, in some cases, those of other energy assets, could have a material adverse effect on our business. Similarly, any future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.

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Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may increase in the future.

Our pipelines, terminals, fractionator and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.

Severe weather events and other climate conditions may adversely affect our facilities and ongoing operations.

Our facilities are subject to potential acute physical risks, such as floods, hurricane-force winds, wildfires and snowstorms, and potential chronic physical risks, such as sea-level rise or water shortages. If any such events were to occur, they could have an adverse effect on our assets and operations. We have incurred and will continue to incur additional costs to protect our assets and operations from such physical risks and employ the evolving technologies and processes available to mitigate such risks. To the extent such severe weather events or other climate conditions increase in frequency and severity, we may be required to modify operations and incur costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.

Financial Risks

We may not have sufficient cash from operations after the establishment of cash reserves and payment of our expenses, including cost reimbursements to MPC and its affiliates, to enable us to pay the intended quarterly distribution to our unitholders.

The amount of cash we can distribute to our common unitholders principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;
the fees and tariff rates we charge and the margins we realize for our services and sales;
the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;
the level of our operating costs including repairs and maintenance;
the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and
prevailing economic conditions.

In addition, the actual amount of cash available for distribution may depend on other factors, some of which are beyond our control, including:

the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC;
our debt service requirements and other liabilities;
fluctuations in our working capital needs;
our ability to borrow funds and access capital markets;
restrictions in our joint venture agreements or agreements governing our debt;
the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;
the cost of acquisitions, if any; and
the amount of cash reserves established by our general partner in its discretion, which may increase in the future and which may in turn further reduce the amount of cash available for distribution.

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Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make distributions during periods when we record net losses and may not make distributions during periods when we record net income.

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flow, and our ability to fulfill our debt obligations.

We have significant debt obligations, which totaled $20.5 billion as of December 31, 2020. We may incur significant debt obligations in the future, including under our loan agreement with MPC. Our existing and future indebtedness may impose various restrictions and covenants on us that could have, or the incurrence of such debt could otherwise result in, material adverse consequences, including:

We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions, or general business purposes on favorable terms, if at all, or our cost of borrowing may increase.
We may be at a competitive disadvantage compared to our competitors who have proportionately less debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures or a downturn in our business or the economy generally.
If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our common units.
The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance our operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. Our ability to comply with these covenants may be impaired from time to time if the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations.
If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make distributions at our intended levels.

Certain of our senior notes, our revolving credit facility and our loan agreement with MPC Investment have variable interest rates. As a result, future interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future prior to the applicable stated maturity.

As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make distributions at our intended levels.

The expected phase out of LIBOR could impact the interest rates paid on our variable rate indebtedness and could cause our interest expense to increase.

A portion of our borrowing capacity and outstanding indebtedness bears interest at a variable rate based on LIBOR. The ICE Benchmark Administration Limited (“ICE”) announced that it will cease calculating and
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publishing all USD LIBOR tenors on June 30, 2023 and cease calculating and publishing certain USD LIBOR tenors on December 31, 2021. Further, U.K. and U.S. regulatory authorities have recently issued statements encouraging banks to cease entering into new USD LIBOR based loans as soon as possible and by no later than December 31, 2021 and to continue to transition away from USD LIBOR based loans in preparation of ICE ceasing to calculate and public LIBOR based rates on June 30, 2023. These developments may cause fluctuations in LIBOR rates and pricing of USD LIBOR based loans that are not transitioned to a new benchmark rate.

The agreements that govern our variable rate indebtedness contain customary transition and fallback provisions in contemplation of the cessation of LIBOR. Nevertheless, at this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may have on LIBOR, other benchmarks or floating rate indebtedness. Uncertainty as to the nature of such potential discontinuance, modification, alternative reference rates or other reforms may materially adversely affect the trading market for securities linked to such benchmarks. Furthermore, the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our floating rate indebtedness to be materially different than expected and could materially adversely impact our ability to refinance such floating rate indebtedness or raise future indebtedness on a cost effective basis.

We are exposed to the credit risks of our key customers and derivative counterparties, and any material non-payment or non-performance by our key customers or derivative counterparties could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. This risk is further heightened during sustained periods of declines of natural gas, NGL and oil prices. To the extent any of our customers are in financial distress or commence bankruptcy proceedings, our contracts with them, including provisions relating to dedications of production, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If a contract with a customer is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any such material non-payment or non-performance could reduce our ability to make distributions to our unitholders.

We may incur losses and additional costs as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments, and we expect to continue their use in the future. If the instruments we use to hedge our exposure to various types of risk are not effective, we may incur losses. Derivative transactions involve the risk that counterparties may be unable to satisfy their obligations to us. The risk of counterparty default is heightened in a poor economic environment. In addition, we may be required to incur additional costs in connection with future regulation of derivative instruments to the extent it is applicable to us.

We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.

We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards such as explosions, fires, pipeline releases, cybersecurity breaches or other incidents involving our assets or operations, could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.

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Legal and Regulatory Risks

We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental or other laws or regulations. Future environmental laws and regulations may impact our current business plans and reduce demand for our services.

Our business is subject to numerous environmental laws and regulations. These laws and regulations continue to increase in both number and complexity and affect our business. Laws and regulations expected to become more stringent relate to the following:

the emission or discharge of materials into the environment;
solid and hazardous waste management;
the regulatory classification of materials currently or formerly used in our business;
pollution prevention;
greenhouse gas emissions;
climate change;
public and employee safety and health;
permitting;
inherently safer technology; and
facility security.

The specific impact of laws and regulations, and their enforcement, on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas and production processes and subsequent judicial interpretation of such laws and regulations. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs due to alleged contamination and/or exposure to chemicals or other regulated materials at or from our facilities. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.

Increased regulation of hydraulic fracturing and other oil and gas production activities could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely affect our results of operations and financial condition.

While we do not conduct hydraulic fracturing operations, we do provide gathering, processing and fractionation services with respect to natural gas and natural gas liquids produced by our customers as a result of such operations. A range of federal, state and local laws and regulations currently govern or, in some cases, prohibit, hydraulic fracturing in some jurisdictions. Stricter laws, regulations and permitting processes may be enacted in the future. For example, President Biden has suspended new oil and gas permitting on public lands and properties, and has proposed modifying royalties to account for climate costs. If these or other federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing or other oil and gas production activities are enacted or expanded, such efforts could impede oil and gas production, increase producers’ cost of compliance, and result in reduced volumes available for our midstream assets to gather, process and fractionate.

Climate change and greenhouse gas emission regulation could affect our operations, energy consumption patterns and regulatory obligations, any of which could affect our results of operations and financial condition.

Currently, multiple legislative and regulatory measures to address greenhouse gas (including carbon dioxide, methane and nitrous oxides) and other emissions are in various phases of consideration, promulgation or implementation. These include actions to develop international, federal, regional or statewide programs, which could require reductions in our greenhouse gas or other emissions, establish a carbon tax and decrease the demand for refined products. Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our
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facilities and (iii) administer and manage any emissions programs, including acquiring emission credits or allotments.

Regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and considerable uncertainty due to a number of factors including technological feasibility, legal challenges and potential changes in federal policy. Increasing concerns about climate change and carbon intensity have also resulted in societal concerns and a number of international and national measures to limit greenhouse gas emissions. Additional stricter measures and investor pressure can be expected in the future and any of these changes may have a material adverse impact on our business or financial condition.

International climate change-related efforts, such as the 2015 United Nations Conference on Climate Change, which led to the creation of the Paris Agreement, may impact the regulatory framework of states whose policies directly influence our present and future operations. Though the United States had withdrawn from the Paris Agreement, President Biden issued an executive order recommitting the United States to the Paris Agreement on January 20, 2021. President Biden also issued an Executive Order on climate change in which he announced putting the U.S. on a path to achieve net-zero carbon emissions, economy-wide, by 2050. The Executive Order also calls for the federal government to pause oil and gas leasing on federal lands, reduce methane emissions from the oil and gas sector as quickly as possible, and requires federal permitting decisions to consider the effects of greenhouse gas emissions and climate change. In a second Executive Order, President Biden reestablished a working group to develop the social cost of carbon and the social cost of methane. The social cost of carbon and social cost of methane can be used to weigh the costs and benefits of proposed regulations. A higher social cost of carbon could support more stringent greenhouse gas emission regulation.

The scope and magnitude of the changes to U.S. climate change strategy under the Biden administration and future administrations, however, remain subject to the passage of legislation and interpretation and action of federal and state regulatory bodies; therefore, the impact to our industry and operations due to greenhouse gas regulation is unknown at this time.

Energy assets and companies are subject to increasing environmental and climate-related litigation.

Governmental and other entities in various U.S. states have filed lawsuits against coal, gas, oil and petroleum companies, including MPC, upon which we depend for a substantial portion of our business. The lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions. Additionally, private plaintiffs and government parties have undertaken efforts to shut down energy assets by challenging operating permits, the validity of easements or the compliance with easement conditions. For example, the Dakota Access Pipeline, in which we have a minority interest, has been subject to litigation in which plaintiffs have challenged the validity of an easement necessary for the operation of the pipeline and demanded a permanent shutdown of the pipeline. There remains a high degree of uncertainty regarding the ultimate outcome of these types of proceedings, as well as their potential effect on our business, financial condition, results of operation and cash flows.

We are subject to risks associated with societal and political pressures and other forms of opposition to the development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and ability to realize certain growth strategies.

We operate and develop our business with the expectation that regulations and societal sentiment will continue to enable the development, transportation and use of carbon-based fuels. However, policy decisions relating to the production, refining, transportation, storage and marketing of carbon-based fuels are subject to political pressures and the influence and protests of environmental and other special interest groups.

The approval process for storage and transportation projects has become increasingly challenging, due in part to state and local concerns related to pipelines, negative public perception regarding the oil and gas industry, and concerns regarding greenhouse gas emissions downstream of pipeline operations. In addition, government disruptions may delay or halt the granting and renewal of permits, licenses and other items required by us and our customers to conduct our business. Our expansion or construction projects may not be completed on schedule (or at all), or at the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and
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the surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly.

Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we may not receive any material increases in revenues until after completion of the project, if at all. Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results, thereby limiting our ability to grow and generate cash flows.

Certain of our facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.

Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands.

We are indemnified for certain environmental liabilities arising from properties on which certain of our facilities are located and our results of operations and our ability to make distributions to our unitholders could be adversely affected if an indemnifying party fails to perform its indemnification obligations.

Prior third-party owners or operators of certain of our facilities, or such parties’ successors-in-interest, have in certain circumstances agreed to retain full or partial liability and responsibility for, or to indemnify us against, any environmental liabilities associated with these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased and to the extent not contributed to by us. Our results of operations and our ability to make cash distributions to our unitholders could be adversely affected if in the future any of these third parties fail to perform their indemnification obligations. In addition, from time to time, we have acquired, and may acquire in the future, facilities from third parties which previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. In some cases, we may receive indemnification from the prior owner or operator for some or all of such liabilities, and in other cases we may accept some or all of such liabilities. There is no assurance that any such third parties will perform any such indemnification obligations, or that the obligations and liabilities that we may accept in connection with any such acquisition will not be larger than anticipated, and in such event, our results of operations and cash available for distribution could be adversely affected.

Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our business.

We do not own all of the land on which our assets are located, but rather obtain the rights to construct and operate such assets on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the possibility of more burdensome terms and increased costs to obtain and retain necessary land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined that we do not have valid leases, rights-of-way or other property rights. Any loss of or reduction in these rights, including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way agreements or permits on satisfactory terms or at all, could have a
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material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

If foreign investment in us or our general partner exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

The Shipping Act of 1916 and Merchant Marine Act of 1920 (collectively, the “Maritime Laws”), generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.

Certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to our unitholders.

Some of our natural gas, crude oil, NGL, and refined product pipelines are, or may in the future be, subject to siting, public necessity or service regulations by FERC or various state or other regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs, crude oil and refined products in interstate commerce and FERC’s regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities (for natural gas pipelines only); rates; operations; accounts and records; and depreciation and amortization policies. FERC’s action in any of these areas or modifications of its current regulations can adversely impact our ability to compete for business, the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of operating our pipelines. FERC also may conduct audits of these facilities, and if FERC determines that we are not in compliance with our tariff or applicable regulations, we may incur additional costs, expenses or penalties. For certain natural gas, NGL, crude oil and refined product common carrier pipelines, we have FERC tariffs on file and we may have additional pipelines in the future that may be subject to these requirements. We also own and are constructing pipelines that we believe are either not subject to FERC’s jurisdiction or would otherwise meet the qualifications for a waiver from many or all of FERC’s requirements. However, we cannot provide assurance that FERC will not at some point find that some or all of these pipelines are subject to FERC’s requirements or are otherwise not exempt from certain requirements. Such a finding could subject us to potentially burdensome and expensive operational, reporting and other requirements as well as fines, penalties or other sanctions.

Pipelines and operations not subject to regulation by FERC may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services and that we offer service to our shippers on a not unduly discriminatory basis. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business – Regulatory Matters as set forth in this Annual Report on Form 10-K.

Some of our natural gas, NGL, crude oil and refined product pipelines are subject to FERC’s rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.

A number of our pipelines provide interstate service that is subject to regulation by FERC. FERC prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines. FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in FERC’s approved rate methodologies, or challenges to our application of an approved methodology, could also adversely affect our rates. Additionally, shippers may protest (and FERC may investigate) the lawfulness of tariff rates. FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.

Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or
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against us could have a material adverse effect on our business, financial condition and results of operations.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs, and the expansion of pipeline safety laws and regulations could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.

The DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could do the most harm. The regulations require the following of operators of covered pipelines to:

perform ongoing assessments of pipeline integrity;
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
improve data collection, integration and analysis;
repair and remediate the pipeline as necessary; and
implement preventive and mitigating actions.

Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. The adoption of additional laws or regulations that apply more comprehensive or stringent safety standards to gas, NGL, crude oil and refined product lines or other facilities, or the expansion of regulatory inspections by regulators, could require us to install new or modified safety controls, pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased capital and operational costs or operational delays that could be significant and have a material adverse effect on our financial position or results of operations and ability to make distributions to our unitholders.

Strategic Transaction Risks

We have recorded goodwill and other intangible assets that could become impaired and result in material non-cash charges to our results of operations in the future.

We accounted for the Merger as a reorganization of entities under common control in accordance with accounting principles generally accepted in the United States. Under a reorganization of entities under common control, the assets and liabilities of ANDX transferred between entities under common control were recorded by MPLX based on MPC’s historical cost basis resulting from its preliminary purchase price accounting. We recorded ANDX’s assets and liabilities at MPC’s basis as of October 1, 2018, the date that common control was first established.

Effective October 1, 2018, MPC acquired Andeavor, including a controlling interest in ANDX, thus establishing common control between MPLX, ANDX and their respective general partners. Under MPC’s application of the acquisition method of accounting, a portion of the total purchase price was allocated to ANDX’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of October 1, 2018. The excess of the allocated purchase price over those fair values was recorded as goodwill.

As of December 31, 2020, our balance sheet reflected $7.7 billion and $1.0 billion of goodwill and intangible assets, respectively. In 2020, we recorded approximately $2.0 billion in impairment expense related to goodwill and intangible assets. To the extent the value of goodwill or intangible assets becomes further impaired, we may be required to incur additional material non-cash charges relating to such impairment. Our operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.

If we are unable to make strategic acquisitions on economically acceptable terms from MPC or third parties, our ability to implement our business strategy may be impaired.

In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions. If we are unable to make accretive strategic acquisitions from
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MPC or third parties that increase the cash generated from operations per unit, whether due to an inability to identify attractive acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.

Future acquisitions will involve the integration of new assets or businesses and may present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.

Future transactions involving the addition of new assets or businesses will present potential risks, which may include, a