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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, 2019

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)
Delaware
 
27-0005456
(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 class
Trading Symbol(s)
Name of each exchange on which registered
Common Units Representing Limited Partnership Interests
MPLX
New 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 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 28, 2019 was approximately $9.3 billion. This amount is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 28, 2019. 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 1,058,415,865 common units outstanding at February 17, 2020.

DOCUMENTS INCORPORATED BY REFERENCE: None


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Table of Contents
 
 
 
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.
Form 10-K Summary
 
Signatures

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:
ARO
Asset retirement obligation
ASC
Accounting Standards Codification
ASU
Accounting Standards Update
ATM Program
An 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/d
One billion cubic feet per day
Btu
One British thermal unit, an energy measurement
Condensate
A 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
DOT
United States Department of Transportation
EBITDA (a non-GAAP financial measure)
Earnings Before Interest, Taxes, Depreciation and Amortization
EPA
United States Environmental Protection Agency
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
Gal
Gallon
Gal/d
Gallons per day
IDR
Incentive Distribution Right
Initial Offering
Initial public offering on October 31, 2012
IRS
Internal Revenue Service
Joint-Interest Acquisition
On September 1, 2017, MPLX acquired certain ownership interests in joint venture entities indirectly held by Marathon Petroleum Corporation (“MPC”), collectively:
- Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”)
- LOOP LLC (“LOOP”)
- LOCAP LLC (“LOCAP”)
- Explorer Pipeline Company (“Explorer”)
LIBOR
London Interbank Offered Rate
MarkWest Merger
On December 4, 2015, a wholly-owned subsidiary of MPLX merged with MarkWest Energy Partners, L.P. (“MarkWest”)
mbbls
Thousands of barrels
mbpd
Thousand barrels per day
mcf
One thousand cubic feet
MMBtu
One million British thermal units, an energy measurement
MMcf/d
One million cubic feet per day
NGL
Natural gas liquids, such as ethane, propane, butanes and natural gasoline
NYSE
New York Stock Exchange
OTC
Over-the-Counter
Partnership Agreement
Fifth Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of July 30, 2019
PHMSA
Pipeline and Hazardous Materials Safety Administration
PPI
Producer Price Index


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Predecessor
Collectively:
- The related assets, liabilities and results of operations of Hardin Street Marine LLC (“HSM”) prior to the date of the acquisition, March 31, 2016, effective January 1, 2015
- 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 Andeavor Logistics LP (“ANDX”) prior to the date of the acquisition, July 30, 2019, effective October 1, 2018.
Realized derivative gains/losses
The gain or loss recognized when a derivative matures or is settled
SEC
United States Securities and Exchange Commission
SMR
Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, Texas
Unrealized derivative gains/losses
The gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling
USCG
United States Coast Guard
VIE
Variable interest entity


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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 levels of revenues and other income, income from operations, net income attributable to MPLX LP, earnings per unit, Adjusted EBITDA or DCF (see the Non-GAAP Financial Information section below for the definitions of Adjusted EBITDA and DCF);
future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;
the success or timing of completion of ongoing or anticipated capital or maintenance projects;
the amount and timing of future distributions; 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:
Marathon Petroleum Corporation’s (“MPC”) ability to achieve its strategic objectives and the effects of those strategic decisions on us;
the risk that anticipated opportunities and any other synergies from or anticipated benefits of the Andeavor Logistics LP (“ANDX”) acquisition may not be fully realized or may take longer to realize than expected, including whether the transaction will be accretive within the expected timeframe or at all;
disruption from the ANDX acquisition making it more difficult to maintain relationships with customers, employees or suppliers;
risks relating to any unforeseen liabilities of ANDX;
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; and
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;

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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;
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, including the dropdowns completed by MPC, 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. The assets and operations of our L&S and G&P segments described above include the assets and operations of ANDX acquired via merger on July 30, 2019. This acquisition complemented our existing business in addition to expanding our operations to the West Coast. 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, 2019:

403064495_updatedmplxoperationsmap.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. This includes agreements obtained through our acquisition of ANDX, whereby ANDX had similar agreements with MPC. As of December 31, 2019, MPC owned approximately 63 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

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resource plays, including the Permian Basin, Marcellus Shale, Utica Shale, STACK Shale and Bakken Shale, among others.

The growth of our business has provided us with the financial flexibility to maintain an investment grade credit profile and fund our organic growth capital plan with operating cash and debt. We have significant opportunities to develop, expand and participate in projects which complement our existing assets. We continue to evaluate our non-organic growth opportunities through third-party midstream acquisitions to enhance our existing geographic footprint or expand our activities into new areas.

2019 RESULTS

The following table summarizes the operating performance for each segment for the year ended December 31, 2019. 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.
403064495_businesssegmentresults.jpg
(1)
Includes goodwill impairment of $1.2 billion within our G&P operating segment.
(2)
Includes segment adjusted EBITDA attributable to predecessor.

2019 ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS

MPLX completed its acquisition of ANDX (the “Merger”) on July 30, 2019. The historical results of ANDX have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired Andeavor (the former sponsor of ANDX). At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The assets of ANDX complement and enhance MPLX’s asset base and further expand MPLX’s existing footprint.


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In connection with the Merger, MPLX assumed all outstanding ANDX senior notes, which had an aggregate principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion new unsecured senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX, of which $500 million aggregate principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid off at maturity on October 15, 2019.

During the year, MPLX also: entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement (as defined below) to $3.5 billion; and extended the maturity of the MPLX Credit Agreement to July 30, 2024.

MPLX entered into a joint venture agreement (“Wink to Webster Pipeline JV”) related to the Wink-to-Webster crude oil pipeline, which remains on schedule to be completed in the first half of 2021 and has 100 percent of the contractible capacity committed with minimum volume commitments. This pipeline is designed to be a 36-inch diameter pipeline with a capacity of 1.5 million barrels per day originating in the Permian Basin and with destination points in the Houston market, including MPC’s Galveston Bay refinery.

We also entered into a joint venture agreement related to the design and construction of the Whistler Pipeline. The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport approximately 2 billion Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The majority of available capacity on the planned pipeline has been committed with minimum volume commitments. The pipeline is expected to be in service in the third quarter of 2021.

Additionally, we continue to execute on our organic growth plan through terminal and marine fleet expansions, the expansion of processing and fractionating capacity at numerous plants, as well as having a continued focus on the optimization of our portfolio of assets, which could include asset divestitures.

RECENT DEVELOPMENTS

On February 21, 2020, MPLX, through a wholly-owned subsidiary, formed a joint venture with Delek US Energy, Inc. ("Delek") (the "WWP Project Financing JV") for the specific purpose of financing a portion of MPLX’s and Delek’s combined construction costs for the Wink to Webster pipeline system. Both MPLX and Delek contributed their respective 15 percent ownership interests in the Wink to Webster Pipeline JV to the WWP Project Financing JV. Also on February 21, 2020, the WWP Project Financing JV, through a wholly-owned subsidiary, entered into a committed term loan facility with a syndicate of lenders providing for up to approximately $608 million in term loan borrowings to, among other things, fund future capital calls received from the Wink to Webster Pipeline JV and pay debt service costs under the term loan facility prior to the commercial operation date of the Wink to Webster pipeline system. The WWP Project Financing JV pledged the combined 30 percent interest in the Wink to Webster Pipeline JV contributed to it by MPLX and Delek to secure its obligations under the term loan facility.

On January 23, 2020, 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 14, 2020 to common unitholders of record on February 4, 2020.

MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value through a review of its Midstream business and to analyze, among other things, the strategic fit of assets with MPC, the ability to realize full valuation credit for midstream earnings and cash flow, balance sheet impacts including liquidity and credit ratings, transaction tax impacts, separation costs, and overall complexity.


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BUSINESS STRATEGIES

Our primary business objective is to enhance the generation of stable cash flows through executing the following strategies:
Capture Full Midstream Value Chain: We intend to develop incremental infrastructure to support growth across the hydrocarbon value chain. Touch points across the value chain include gathering, processing, fractionation, and inbound/outbound logistics assets such as long-haul pipelines and export facilities. This diversification and integration provide multiple sources of stable fee-based revenue while also enhancing opportunities for third-party revenue capture.
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 will enhance our ability to meet significant growing market needs both domestically and globally.
Growth in Premier Basins: Our assets are located in some of the premier production areas in the United States. Our business strategy and investments are focused on connecting supply to global demand markets. We intend to increase operating cash flow by investing in opportunities that may arise in our areas of operations and increasing the utilization of our existing facilities. We will evaluate organic growth projects both within our geographic footprint as well as in new areas that we consider strategic.
Maintain Financial Discipline: We high-grade our portfolio of investment opportunities to ensure efficient deployment of capital focusing on mid-teen returns. Our goal is to optimize our cost of capital by maintaining an investment grade credit profile and funding our organic growth capital plan with operating cash and debt. The company does not intend to issue public equity to fund its organic growth capital needs.
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.


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ORGANIZATIONAL STRUCTURE

The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 17, 2020.

403064495_mplxorgchart2019.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, 2019, 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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403064495_lsflowdiagram.jpg

Crude oil is the primary raw material for transportation fuels and the basis for many products including plastics and petrochemicals, in addition to heating oil for homes once it is refined and prepared for use. 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:
403064495_gpflowdiagram.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

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competitive advantage. Well-positioned operations allow access to all major NGL markets and provide for 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, with its acquisition of Andeavor effective October 1, 2018, is the largest crude oil refiner in the United States in terms of refining capacity. MPC owns and operates 16 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, and through company owned and operated convenience stores across the United States, including under the Speedway brand.

MPC retains a significant interest in us through its non-economic ownership of our general partner and holding approximately 63 percent of the outstanding common units of MPLX as of December 31, 2019. 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, 2019, 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 over 13,000 miles of pipeline throughout the continental United States and Alaska. Our storage caverns consist of butane, propane, and liquefied petroleum gas storage with a combined capacity of 4.7 million barrels located 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, and have a combined total shell capacity of approximately 34 million barrels. 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 23 boats and 286 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. Additionally, our fuels distribution business provides MPC with a broad range of scheduling and marketing services. 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.

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Projects
 
New or expanded capacity
 
Expected in-service of expansion capacity
Mt. Airy Terminal Expansion-construction of second export dock
 
120 mbpd
 
2020
Mt. Airy Terminal Expansion-incremental refined product storage
 
TBD
 
2020
Wink to Webster Pipeline-crude oil pipeline
 
1,500 mbpd
 
2021
Whistler Pipeline-natural gas pipeline
 
2,000 MMcf/d
 
2021
BANGL Pipeline-NGL pipeline
 
500 mbpd
 
2021
Gulf Coast C2+ Fractionation-construction of NGL fractionators
 
450 mbpd
 
2021-2024
Texas City Export Terminal-NGL storage and export facilities
 
TBD
 
2022
Carson Crude Terminal Expansion-incremental crude storage
 
2,000 mbbls
 
2022

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 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 while our wholesale business includes the operations of several bulk petroleum distribution plants and a fleet of refined product delivery trucks that distribute commercial wholesale petroleum products. 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, 2019, approximately 91 percent of L&S segment operating income 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, 2019, our gathering and processing assets include approximately 9.0 Bcf/d of gathering capacity, 11.6 Bcf/d of natural gas processing capacity and 831 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.

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Plant
Existing capacity
 
New or expanded capacity
 
Expected in-service of expansion capacity
 
Geographic Region
Processing (MMcf/d):
 
 
 
 
 
 
 
Smithburg Complex(1)

 
1,200

 
TBD
 
Marcellus Operations
Western Oklahoma Complex
545

 
180

 
2020
 
Southwest Operations
Preakness Complex

 
200

 
2020
 
Southwest Operations
Fractionation (mbpd):
 
 
 
 
 
 
 
Hopedale Complex
240

 
80

 
2020
 
Marcellus/ Utica Operations
(1)
This is a Sherwood Midstream LLC (“Sherwood Midstream”) investment. The first of six processing plants within this complex is scheduled to be in-service during 2020 with a processing capacity of 200 MMcf/d. The estimated completion dates for the five remaining plants are to be determined.

A significant portion of our business comes from a limited number of key customers. For the year ended December 31, 2019, revenues earned from two customers are significant to the segment, each accounting for approximately 14 percent of G&P operating revenues and six percent of consolidated operating revenues, respectively.

The following table summarizes our key producer customers and attributes for each geographic region:
 
Key Producer Customers
 
Volume Protection
Marcellus Operations(2)
Antero Resources,(1) Range Resources, Penn Energy, Southwestern,(1) CNX, EQT,(1) HG Energy,(1)  and others
 
74% of 2019 capacity contains minimum volume commitments
Utica Operations(2)
Ascent, Gulfport, Antero Resources,(1)   Marathon, EQT and others
 
27% of 2019 capacity contains minimum volume commitments
Southern Appalachian Operations
Diversified Southern Midstream,(1) and Core Appalachia Midstream
 
24% of 2019 capacity contains minimum volume commitments
Southwest Operations(2)
Encana, WSGP Gas Producing LLC, Chevron USA, BP and others
 
5% of 2019 capacity contains minimum volume commitments
Bakken Operations(2)
Whiting Oil and Gas Corporation,(1) Oasis Petroleum,(1) Equinor Energy(1)
 
N/A
Rockies Operations(2)
Pinedale Energy Partners,(1) XTO,(1) EOG(1)
 
39% of 2019 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 provide 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 two fuels distribution agreements with MPC under which we provide scheduling and marketing services of MPC’s products.


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The following table sets forth additional information regarding our transportation, terminal, fuels distribution, and storage services agreements with MPC:
Agreement
 
Initiation Date
 
Term (years)(1)
 
MPC minimum
 commitment(2)
Transportation Services (mbpd):
 
 
 
 
 
 
Crude pipelines
 
Various
 
4-15

 
1,842

Refined product pipelines
 
Various
 
6-15

 
1,910

Marine
 
January 2015
 
6

 
N/A(3)

Trucking Services
 
October 2014
 
1-10

 
50

Storage Services (mbbls):
 
 
 
 
 
 
Caverns
 
Various
 
10-17

 
4,375

Tank Farms(4)
 
Various
 
3-10

 
125,499

Terminal Services(5)
 
Various
 
Various

 
206,272

Fuels Distribution Services (million gallons)
 
Various
 
10

 
23,774

(1)
Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, 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 one to five years 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 one of our two Fuels Distribution Services Agreements. These renewals are automatic, unless terminated by either party.
(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 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 some of our trucking transportation agreements, if MPC fails to request the minimum volume commitment to be gathered and delivered, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the trucking rate then in effect.

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

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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. Additionally, we have a wholesale fuels distribution services agreement as a result of the Merger, under which we are required to sell and deliver product to MPC, and MPC is required to purchase and accept delivery of product from us. MPC pays us an amount equal to our product cost at each terminal, plus applicable taxes and fees, actual transportation cost and a contracted margin. In the event that MPC fails to purchase the committed volume, MPC pays an agreed upon amount for each gallon below the committed volume and will receive a credit for excess volumes purchased in subsequent months to the extent that shortfall payment were made in the prior twelve months. MPC also provides us margin shortfall support for non-delivered rack sales.

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 five joint interest pipelines including Andeavor Logistics Rio Pipeline 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.

Terminal Services Agreements with Third Parties

We have multiple 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 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.

Management Services Agreement with MPC

MPLX has a management services agreement with MPC under which it provides management services to assist MPC in the oversight and management of the marine business. MPLX receives a fixed annual fee for providing the required management services. This fee is adjusted annually on the anniversary of the contract for inflation and any changes in the scope of the management services provided. This agreement is set to expire on January 1, 2021 and automatically renews for two additional renewal terms of five years each unless terminated by either party.


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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. Breakage is estimated and 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 NGL’s 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. This agreement renews automatically on a year-to-year basis, unless terminated by either party.


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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 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, and the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.

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.


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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.

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. Many 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.

Our G&P segment can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in 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 extensive regulations. The failure to comply with applicable laws and regulations or to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and other costs to MPLX. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. The following is a summary of some of the environmental, health and safety laws and regulations to which our operations are subject.

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 Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and its implementing 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 reparations, 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.


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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 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.

FERC issued a policy statement in May 2005 stating that it would permit interstate petroleum pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s 2005 policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. FERC’s 2005 income tax policy was the subject of various appeals by shippers, before FERC and the courts, and United States Court of Appeals for the District of Columbia Circuit issued a ruling that remanded a case related to pass-through entities and the income tax allowance back to FERC for further review and consideration. In response, FERC issued a Revised Policy Statement on the Treatment of Income Taxes on March 15, 2018 indicating, among other things, that interstate petroleum pipelines held by master limited partnerships would no longer be allowed to recover an income tax allowance in cost-of-service rates. This particular matter is currently in briefing before the United States Court of Appeals for the District of Columbia Circuit, and we cannot guarantee that FERC or the courts will not make changes to the policy in the future.

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

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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. MPC has agreed not to contest our tariff rates for the term of our transportation and storage services agreements with MPC, but we do not have any of these types of agreements with third parties. 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.

If our rate levels were investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs.

If FERC or a state commission were to determine that our rates were or had become unjust and unreasonable, we could be ordered to reduce rates prospectively and pay refunds and/or reparations to shippers.

FERC-Regulated Natural Gas Pipelines.

Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, we have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and MarkWest Pioneer, L.L.C., with respect to our Hobbs Pipeline and the Arkoma Connector Pipeline. In addition, gas tariffs are on file for Rendezvous Pipeline Company LLC, which moves gas into Kern River Transmission. Additionally, we have ownership interests in joint ventures with FERC gas tariffs on file.

Under the Natural Gas Act (“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.

On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”). Under the 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. The

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anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority.

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 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.


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Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. 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.

Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 Code of Federal Regulations (“C.F.R.”) Part 192, which governs construction standards and operation of certain natural gas gathering pipelines. The changes that have been proposed include, but are not limited to, more stringent construction standards for remote facilities, as well as additional record-keeping requirements. Depending upon the nature of the final rule-making, those could have an impact upon MPLX LP operations. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.

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.

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.

Propane Regulation.

National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies and in others they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the DOT. We conduct ongoing training programs to help ensure that our operations comply with applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our propane operations. We believe that the procedures currently in effect at all of our facilities for the

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handling, storage and distribution of propane are consistent with industry standards and comply in all material respects with applicable laws and regulations.

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 us. 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. Since the events of September 11, 2001, the United States government has taken steps to increase security of United States ports, coastal waters and inland waterways. We believe that it is unlikely that the current cabotage provisions of the Jones Act would be modified or eliminated in the foreseeable future.

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.

Pipeline Interconnections.

One or more of our plants include pipeline interconnections to, or incidental gathering pipelines that connect the plants to, interstate pipelines. These pipeline interconnections are an integral part of our facilities and are not currently being used, nor can they be used in the future, by any third party due to their origin points at our proprietary facilities. Therefore, we believe these pipeline interconnections are part of our plant facilities and are not subject to the jurisdiction of FERC. In the event that FERC were to determine that these pipeline interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a waiver from most FERC reporting and filing requirements. In the event that FERC were to determine that the pipeline interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC for the pipeline interconnections, provide a cost justification for their transportation rates and provide service to all potential shippers without undue discrimination. In such event, we may experience increased operating costs and reduced revenues.

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.


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ENVIRONMENTAL REGULATION

Our management is responsible for ensuring that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations, and for reviewing our overall environmental performance. We also have a Corporate Emergency Response Team that oversees our response to any major environmental or other emergency incident involving us or any of our facilities.

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. The cost to comply with these laws and regulations cannot be estimated at this time, but could be significant. For additional information, see Item 1A. Risk Factors. Additionally, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable.

Our operations are subject to numerous laws and regulations relating to the protection of the environment. Such laws and regulations include, among others, the ICA with respect to liquids pipelines, the Clean Air Act with respect to air emissions, 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. In addition, many states where we operate have similar laws. 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.

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

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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 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.

Ongoing Remediation and Indemnification from Third Parties

The prior third-party owner or operator of our Cobb, Boldman, Kenova, Kermit and Majorsville facilities, has been, or is currently involved in, certain investigatory or remedial activities with respect to the real property underlying these facilities. The third party or, in the case of the Kermit Complex, its successor in interest, has accepted sole liability and responsibility for, and indemnifies us against those activities or any other environmental condition related to the real property prior to the effective dates of our lease or purchase of the real property that are not contributed to by us. In addition, the third party, or in the case of the Kermit Complex, its successor in interest, has agreed to perform all the required response actions at its expense in a manner that minimizes interference with our use of the properties. We understand that to date, all required actions have been or are being performed and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

The prior third-party owner and/or operator of certain facilities on the real property on which our rail facility is constructed near Houston, Pennsylvania has been, or is currently involved in, investigatory or remedial activities related to acid mine drainage (“AMD”) with respect to the real property underlying these facilities. These investigatory and remedial obligations arise out of an arrangement entered into between the Pennsylvania Department of Environmental Protection and the third party, which has accepted liability and responsibility for, and indemnifies us against, any environmental liabilities associated with the AMD that are not exacerbated by us in connection with our operations. In addition, the third party has agreed to perform all of the required response actions at its expense in a manner that minimizes interference

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with our use of the property. We understand that to date, all actions required under these agreements have been or are being performed and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

We are also entitled to indemnification from MPC for certain assets we acquired from MPC. In addition, from time to time, we have acquired, and we may acquire in the future, facilities from third parties or MPC that previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. The terms of each acquisition will vary, and in some cases, we may receive contractual indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such liabilities that MPLX may bear with respect to any such properties previously acquired by MPLX will have a material adverse impact on our financial condition or results of operations.

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.

Additionally, OPA-90 requires that new tank vessels entering or operating in U.S. waters be double-hulled and that existing tank vessels that are not double-hulled be retrofitted or removed from U.S. service. All barges used for river transport of our raw materials and refined products meet the double-hulled requirements of OPA-90. 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, 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 (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.


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Air Emissions

The 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 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 ppb to 70 ppb. This revision initiated a multi-year process in which nonattainment designations will be made based on more recent ozone measurements that includes data from 2016. On November 6, 2017, the EPA finalized ozone attainment/unclassifiable designations for certain areas under the new standard. In actions dated April 30, 2018 and July 25, 2018, the EPA finalized nonattainment designations for certain areas under the lower primary ozone standard. In some areas, these nonattainment designations could result in increased costs associated with, or result in cancellation or delay of, capital projects at our or our customers’ facilities. For areas designated nonattainment, states will be required to adopt State Implementation Plans (“SIPs”) for nonattainment areas. These SIPs may include NOx and/or volatile organic compound (“VOC”) reductions that could result in increased costs to us or our customers. We cannot predict the effects of the various SIPs 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

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requirements including the imposition of a carbon tax. The EPA’s 2016 New Source Performance Standards (“NSPS”) for the oil and gas industry are 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 as part of the former Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. This rule is currently being challenged in court by various affected states, and in September 2019, the EPA proposed amendments that would rescind the methane emission regulations from the NSPS rule. 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.

Under the National Environmental Policy Act, environmental assessments must be performed for certain projects, including construction of certain new pipelines. 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. Moreover, as a result of a settlement approved by the United States District Court for the District of Columbia in September 2011, the United States Fish and Wildlife Service (“FWS”) is required to make a determination on listing numerous species as endangered or threatened under the ESA by completion of the agency’s 2017 fiscal year. For example, in April 2015, the FWS published a final rule listing the Northern Long Eared Bat as threatened under the ESA. In another example, in September 2016, the FWS announced the listing of the Eastern Massasauga rattlesnake as a threatened species under the ESA. In addition, in January 2017, FWS issued a final rule listing the rusty patched bumblebee as an endangered species effective in February 2017. All of these species, along with the other endangered species such as the Indiana Bat and American Burying Beetle, are in areas in which we operate. The listing of these or other species as threatened or endangered 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

Our assets are subject to increasingly strict safety laws and regulations. The transportation and storage of natural gas and crude oil and refined products involve a risk that hazardous liquids may be released into the

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environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages and significant business interruption.

At manned facilities, the workplaces associated with the processing and storage facilities and the pipelines we operate are subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended (“OSHA”), as well as comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard-communication standard requires that we maintain information about hazardous materials used or produced in operations, and that this information be provided to employees, state and local government authorities and citizens. 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.

At manned and unmanned facilities, the EPA’s Risk Management Planning requirements at regulated facilities are intended to protect the safety of the surrounding public. 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 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.


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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.

Pipeline Control and Monitoring

The majority of our pipelines are operated from central control rooms. These control centers operate with a SCADA (supervisory control and data acquisition) system equipped with computer systems designed to continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and alarm conditions. These systems include leak detection monitoring and alarms if pre-established operating parameters are exceeded. These control centers operate remote pumps, motors and valves associated with the receipt and delivery of products, and provide for the remote-controlled shutdown of pump stations on the pipelines. These systems also include fully functional back-up operations maintained and routinely operated throughout the year to ensure safe and reliable operations.

We monitor the structural integrity of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing and direct assessment, that conform to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent integrity assessments. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test and record the effectiveness of these corrosion inhibiting systems.

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 also proposed product quality specifications for natural gasoline used for blendstock in ethanol flex fuel. The EPA has also established product quality specifications related to butane blending, 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.


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Tribal Lands

Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. For example, the EPA has established a preconstruction permitting program for new and modified minor sources throughout Native American tribal lands, and new and modified major sources in nonattainment areas in those areas. 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.

EMPLOYEES

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. Our general partner and its affiliates have approximately 6,200 full-time employees that provide services to us under our employee services agreements. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

AVAILABLE INFORMATION

General information about MPLX LP and our general partner, MPLX GP, 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.

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. Some of these risks relate principally to our business, the business and operations of MPC and the industry in which we operate, while others relate principally to tax matters, ownership of our common units and the securities markets generally.

Our business, financial condition, results of operations or cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline.

Risks Relating to Our Business

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 $20.7 billion as of December 31, 2019. We may incur significant debt obligations in the future, including under our loan agreement with MPC. Our existing and

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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.

A significant decrease in oil and natural gas production in our areas of operation, whether due to sustained declines in oil, natural gas and NGL prices, natural declines in well production, or otherwise, may adversely affect our revenues, financial condition, 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.