MPLX LP - Annual Report: 2021 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the fiscal year ended December 31, 2021
OR
☐ 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No x
The aggregate market value of common units held by non-affiliates as of June 30, 2021 was approximately $11.2 billion. This amount is based on the closing price of the registrant’s common units on the New York Stock Exchange on June 30, 2021. 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 1,014,627,674 common units outstanding at February 15, 2022.
Documents Incorporated By Reference: None
Table of Contents
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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.
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 | ||||
| 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 | ||||
| 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 | ||||
| IRS | Internal Revenue Service | ||||
| LIBOR | London Interbank Offered Rate | ||||
| mbbls | Thousands of barrels | ||||
| mbpd | Thousand barrels per day | ||||
| MMBtu | One million British thermal units, an energy measurement | ||||
| MMcf/d | One million cubic feet per day | ||||
| MRF | Marine repair facility | ||||
| NGL | Natural gas liquids, such as ethane, propane, butanes and natural gasoline | ||||
| NYSE | New York Stock Exchange | ||||
| PHMSA | Pipeline and Hazardous Materials Safety Administration | ||||
| Predecessor | Collectively: - The related assets, liabilities and results of operations of ANDX prior to the date of the merger, July 30, 2019, effective October 1, 2018. | ||||
| SEC | United States Securities and Exchange Commission | ||||
| USCG | United States Coast Guard | ||||
| VIE | Variable interest entity | ||||
Disclosures Regarding Forward-Looking Statements
This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words such as “anticipate,” “believe,” “commitment,” “could,” “design,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “imply,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “project,” “proposition,” “prospective,” “pursue,” “seek,” “should,” “strategy,” “target,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.
Forward-looking statements include, among other things, statements regarding:
•future financial and operating results;
•environmental, social and governance (“ESG”) goals and targets, including those related to greenhouse gas emissions, diversity and inclusion and ESG reporting;
•our plans to achieve our ESG goals and targets and to monitor and report progress thereon;
•the success or timing of completion of ongoing or anticipated capital or maintenance projects;
•the timing and amount of future distributions or unit repurchases; and
•the anticipated effects of actions of third parties such as competitors, activist investors, 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. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:
•general economic, political or regulatory developments, including inflation, changes in governmental policies relating to refined petroleum products, crude oil, natural gas or NGLs, or taxation;
•the magnitude, duration and extent of future resurgences of the COVID-19 pandemic and its restrictions, including travel restrictions, business and school closures, increased remote work, stay-at-home orders and other actions taken by individuals, governments and the private sector to stem the spread of the virus;
•the ability of MPC to achieve its strategic objectives and the effects of those strategic decisions on us;
•further impairments;
•negative capital market conditions, including an increase of the current yield on common units;
•the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;
•the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, and the effects of any such divestitures on our business, financial condition, results of operations and cash flows;
•the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models;
•the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products;
•volatility in or degradation of market and industry conditions;
•changes to the expected construction costs and timing of projects and planned investments, and the ability to obtain regulatory and other approvals with respect thereto;
•completion of midstream infrastructure by competitors;
•disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;
•the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;
•modifications to financial policies, capital budgets, and earnings and distributions;
•the ability to manage disruptions in credit markets or changes to credit ratings;
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•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 effect of restructuring or reorganization of business components;
•the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;
•foreign imports and exports of crude oil, refined products, natural gas and NGLs;
•changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
•changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks and refined products;
•the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
•actions taken by our competitors, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;
•expectations regarding joint venture arrangements and other acquisitions or divestitures of assets;
•midstream and refining industry overcapacity or undercapacity;
•accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, means of transportation, 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 gathering, transportation, storage, and distribution of crude oil, refined products and other hydrocarbon-based products. We also operate refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. Our G&P segment primarily engages in the gathering, processing and transportation of natural gas as well as the gathering, transportation, fractionation, storage and marketing of NGLs. For more information on these segments, see Our Operating Segments discussion below. The map below and Item 2. Properties provide information about our assets as of December 31, 2021:
We continue to have a strategic relationship with MPC, which is a large source of our revenues. We have executed numerous long-term, fee-based agreements with minimum volume commitments with MPC which provide us with a stable and predictable revenue stream and source of cash flows. As of December 31, 2021, MPC owned our general partner and approximately 64 percent of our outstanding common units. In 2021, MPC accounted for 50 percent of our total revenues and other income, primarily within our L&S segment, and will continue to be an important source of our revenues and cash flows for the foreseeable future. We also have long-term relationships with a diverse set of producer customers in many crude oil and natural gas resource plays, including the Marcellus Shale, Utica Shale, Permian Basin, STACK Shale and Bakken Shale, among others.
Our increased focus on strict capital discipline and adopting a lower cost structure, along with the growth of our business, has provided us with the financial flexibility to maintain an investment grade credit profile, generate cash flow greater than our capital investments and base distributions, and return capital to our unitholders through an
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increase to our distribution, repurchases of our units and a special distribution amount declared for the third quarter of 2021. We continue to evaluate opportunities to develop, expand and participate in projects which complement our existing assets in addition to evaluating non-organic growth opportunities through third-party midstream acquisitions to enhance our existing geographic footprint or expand our activities into new areas. We also continue to assess opportunities to optimize our portfolio of assets through strategic dispositions.
2021 RESULTS
The following table summarizes the operating performance for each segment for the year ended December 31, 2021. For further discussion of our segments and a reconciliation of Non-GAAP measures 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.
(1) Includes impairment expense of $6 million related to an equity method investment within our G&P segment.
(2) Includes impairment expense for equity method investments and property, plant and equipment within our G&P segment of $6 million and $42 million, respectively.
RECENT DEVELOPMENTS
•On January 25, 2022, we announced the board of directors of our general partner had declared a distribution of $0.7050 per common unit that was paid on February 14, 2022 to common unitholders of record on February 4, 2022.
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BUSINESS STRATEGIES
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 and promoting high standards for safety and environmental stewardship.
Enhance Cash Flow Stability: We are focused on growing our fee-based services through long-term contracts, which provide through-cycle cash flow stability. Recent investments in long-haul pipelines are expected to connect supply to demand markets while adding a source of stable cash flow to the company. These investments also expand our export capabilities and enhance our ability to meet significant growing market needs both domestically and globally.
Continued Capital Discipline and Focus on Low Cost Culture: We are focused on lowering our overall cost structure and being disciplined in our capital allocation. We have been focused on lowering our costs in all aspects of our business and a low cost culture is beginning to become embedded in how we conduct our business. We also challenge ourselves to be disciplined in our capital allocation as we look to grow our business and optimize our portfolio of investment opportunities to ensure efficient deployment of capital.
Commitment to Return Capital to Unitholders: We maintain our objective to generate cash flows sufficient to provide cash available for deployment after funding both our capital investments and distributions for 2022. We expect to achieve this through continued earnings growth, strict-capital discipline and adoption of a low-cost culture. We believe generating strong cash flows will enhance our long-term financial flexibility to pursue value creating investments in the business, while also supporting the incremental return of capital.
Commitment to Sustainability: Our approach to sustainability spans the environmental, social and governance dimensions of our business. That means strengthening resiliency by lowering the carbon intensity and conserving natural resources; innovating for the future by investing in renewables and emerging technologies; and embedding sustainability in decision-making and in how we engage our people and many stakeholders. For example, in February 2022, we established a new 2030 target to reduce methane emissions intensity by 75% below 2016 levels. The reduction target applies to our natural gas gathering and processing operations and represents an expansion of our existing 2025 target, established in 2020, to reduce methane emissions intensity by 50% below 2016 levels.
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ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 15, 2022.
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. Refer to Item 7A for information regarding the LIBOR transition.
INDUSTRY OVERVIEW
As of December 31, 2021, 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 gathering, transportation, terminalling, storage and marketing services across the hydrocarbon value chain as depicted below.
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Crude oil is the primary raw material for transportation fuels and the basis for many products, including plastics, petrochemicals and heating oil for homes. Pipelines bring advantaged North American crude oil from the upper Great Plains, Louisiana, Texas, Canada and West Coast to numerous refineries throughout the United States. Terminals provide for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products via pipeline, rail, marine and over-the-road modes of transportation. This network of logistics infrastructure also allows for export opportunities by connecting supply to global demand markets. The hydrocarbon market is often volatile and the ability to take advantage of fast-moving market conditions is enhanced by the ability to store crude oil and other hydrocarbon-based products at tank farms, caverns, and tanks at refineries and terminals. The ability to store both crude and refined 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:
•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, our network of pipelines known as gathering systems directly connect to wellheads in the production area. Our 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. Our natural gas processing complexes remove 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 further 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/fractionation plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the shale plays will likely have a competitive advantage. Well-positioned operations allow access to all
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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 OPERATING SEGMENTS
We conduct our operations in two reportable segments, which include L&S and G&P. Each of these segments is organized and managed based upon the nature of the products and services it offers.
L&S:
The L&S segment includes gathering, transportation, storage and distribution of crude oil, refined products and other hydrocarbon-based products. We also operate refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. 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. For information related to our L&S assets, please see Item 2. Properties - Logistics and Storage. Our L&S assets are integral to the success of MPC’s operations. We continue to evaluate projects and opportunities that will further enhance our existing operations and provide valuable services to MPC and third parties.
We generate revenue in the L&S segment primarily by charging tariffs for gathering and 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. 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, 2021, approximately 90 percent of L&S segment revenues and other income was generated from MPC.
G&P:
The G&P segment gathers, processes and transports natural gas; and gathers, transports, fractionates, stores and markets NGLs. As of December 31, 2021, gathering and processing assets available to MPLX include approximately 10.4 Bcf/d of gathering capacity, 11.8 Bcf/d of natural gas processing capacity, 789 mbpd of fractionation capacity and 23 mbpd of 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.
For the year ended December 31, 2021, revenues earned from two customers are significant to the segment, each accounting for approximately 14 percent of G&P operating revenues and seven percent of consolidated operating revenues, respectively.
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 RELATIONSHIP WITH MPC
One of our competitive strengths is our strategic relationship with MPC, which is the largest crude oil refiner in the United States in terms of refining capacity. MPC owns and operates 13 refineries in the Gulf Coast, Mid-Continent and West Coast regions of the United States and distributes crude and refined products through transportation, storage, distribution and marketing services provided by its midstream segment, which primarily consists of MPLX. MPLX, through its fuels distribution services, distributes refined products under the Marathon brand through an extensive network of retail locations owned or operated by independent entrepreneurs across the United States.
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MPC retains a significant interest in us through its non-economic ownership of our general partner and holding approximately 64 percent of the outstanding common units of MPLX as of December 31, 2021. Given MPC’s significant interest in us, we believe MPC will promote and support the successful execution of our business strategies.
OUR L&S CONTRACTS WITH MPC AND THIRD PARTIES
Transportation Services Agreements, Storage Services Agreements, Terminal Services Agreements and Fuels Distribution Services Agreement with MPC
Our L&S assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple transportation, terminal and storage services agreements with MPC. Under these long-term, fee-based agreements, we provide transportation, terminal and storage services to MPC and, other than under our marine transportation services agreement, most of these agreements include minimum committed volumes from MPC. MPC has also committed to pay a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation services agreement. We also have a fuels distribution agreement with MPC under which we provide scheduling and other services of MPC’s products.
The following table sets forth additional information regarding our transportation, storage, terminal, and fuels distribution services agreements with MPC as expected to be in effect throughout 2022:
| Agreement | Initiation Date | Term (years) | MPC minimum commitment | |||||||||||||||||
| Transportation Services (mbpd): | ||||||||||||||||||||
Crude pipelines(1) | Various | 3-12 | 2,089 | |||||||||||||||||
Refined product pipelines(2) | Various | 1-15 | 1,900 | |||||||||||||||||
Marine(3) | January 2015 | 6 | N/A | |||||||||||||||||
| Storage Services (mbbls): | ||||||||||||||||||||
Tank Farms(4) | Various | 2-12 | 130,415 | |||||||||||||||||
Caverns(5) | Various | 10-17 | 4,764 | |||||||||||||||||
Terminal Services(6) (quarterly terminal throughput, thousands of barrels) | Various | Various | 192,543 | |||||||||||||||||
Fuels Distribution Services(7) (millions of gals per year) | February 2018 | 10 | 23,449 | |||||||||||||||||
(1) Commitments are adjusted for crude viscosity. Renewal terms include multiple two to five-year terms.
(2) Renewal terms include multiple one to five-year terms.
(3) MPC has committed to utilize 100 percent of our available capacity of boats and barges. Renewal terms include two additional five-year terms. The contract is currently within the first renewal period.
(4) Volume shown represents total shell capacity and includes refining logistics tanks. Renewal terms vary and range from year-to-year to multiple additional five-year terms.
(5) Renewal terms vary and range from zero to 10 years. Volume shown represents total shell capacity.
(6) Renewal terms vary and range from month-to-month to two additional five-year terms.
(7) Includes one additional five-year renewal term.
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 a trucking transportation services agreement with MPC. Under this trucking transportation services agreement, we receive a service fee per barrel for gathering barrels and providing trucking, dispatch, delivery and data services.
Under most of our terminal services agreements, if MPC fails to meet its minimum volume commitment during any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. Some of our terminal services agreements contain minimum commitments for various additional services such as storage and blending.
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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 marketed by MPLX each month, subject to a maximum annual volume. MPLX has agreed to use commercially reasonable efforts to sell not less than a minimum quarterly volume of MPC’s products during each calendar quarter. If MPLX sells less than the minimum quarterly volume of MPC’s products during any calendar quarter despite its commercially reasonable efforts, MPC will pay MPLX a deficiency payment equal to the volume deficiency multiplied by the applicable tiered fee. The dollar amount of actual sales volume of MPC’s products that exceeds the minimum quarterly volume (an “Excess Sale”) for a particular quarter will be applied as a credit, on a first-in-first-out basis, against any future deficiency payment owed by MPC to MPLX during the four calendar quarters immediately following the calendar quarter in which the Excess Sale occurs.
Pipeline Operating Agreements with MPC
We operate various pipelines owned by MPC under operating services agreements. Under these operating services agreements, we receive an operating fee for operating the assets, which include certain MPC wholly owned or partially owned crude oil, natural gas, and refined product pipelines, and for providing various operational services with respect to those assets. We are generally reimbursed for all direct and indirect costs associated with operating the assets and providing such operational services. These agreements vary in length and automatically renew with most agreements being indexed for inflation.
Pipeline Operating Agreements with Third Parties
We maintain and operate six pipelines through our joint interests in Andeavor Logistics Rio Pipeline LLC, BANGL LLC, Capline Pipeline Company LLC, Centennial Pipeline LLC, Louisville-Lexington Operation and Muskegon Pipeline LLC. We receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline. The length and renewal terms for each agreement vary.
Transportation and Terminal Services Agreements with Third Parties
We have multiple transportation and terminal services agreements with third parties under which we provide use of pipelines and tank storage, and provide services, facilities and other infrastructure related to the receipt, storage, throughput, blending and delivery of commodities. Some of these agreements are subject to prepaid throughput volumes under which we agree to handle a certain amount of product throughput each month in exchange for a predetermined fixed fee, with any excess throughput or ancillary services subject to additional charges. Under the remaining agreements, we receive an agreed upon fee based on actual product throughput following the completion of services.
Marine Services Agreements with MPC
MPLX has agreements with MPC under which it provides management and loss control services to assist MPC in the oversight and management of the marine business. MPLX receives fixed annual fees for providing the required services, which are subject to predetermined annual escalation rates. These agreements are subject to initial terms of five years and automatically renew for one additional five-year renewal period unless terminated by either party.
Other Agreements with MPC
We have omnibus agreements with MPC that address our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain services to us, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we indemnify MPC for certain matters under these agreements.
We also have various employee services agreements and a secondment agreement under which we reimburse MPC for the provision of certain operational and management services to us. All of the employees that conduct our business are directly employed by affiliates of our general partner.
Additionally, we have certain indemnification agreements with MPC under which MPC retains responsibility for remediation of known environmental liabilities due to the use or operation of the assets prior to our ownership, and
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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. MPLX enters into a variety of contract types including fee-based, percent-of-proceeds, keep-whole and purchase arrangements in order to generate service revenue and product sales. See Item 8. Financial Statements and Supplementary Data - Note 2 for a further description of these different types of arrangements.
In many cases, MPLX provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of MPLX’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. In addition, minimum volume commitments may create contract liabilities or deferred credits if current period payments can be used for future services. These are recognized into service revenue in instances where it is probable the customer will not use the credit in future periods.
MPLX’s contract mix and exposure to natural gas and NGL prices may change as a result of changes in producer preferences, MPLX expansion in regions where some types of contracts are more common and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.
Keep-whole agreement with MPC
MPLX has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGLs related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provides for a base volume subject to a base rate and incremental volumes subject to variable rates, which are calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes are subject to revision each year.
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. Competition for oil supplies is based primarily on the price and scope of services, location of the facility and connectivity to the best priced markets.
As a result of our contractual relationship with MPC under our transportation and storage services agreements, our terminal services agreement, our fuels distribution agreement and our physical asset connections to MPC’s refineries and terminals, we believe that MPC will continue to utilize our assets for transportation, storage, distribution and marketing services. If MPC’s customers reduced their purchases of refined products from MPC due to increased availability of less expensive refined product from other suppliers or for other reasons, MPC may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which could decrease our revenues.
In our G&P segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering, transportation and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability, residue gas and NGL market connectivity, the ability to obtain a satisfactory price for products recovered and the fees charged for services supplied to the customer. Competitive factors affecting our fractionation services include availability of fractionation capacity, proximity to supply and industry marketing centers, the fees charged for fractionation services and operating efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, credit and market connectivity.
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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.
Certain competitors, such as major oil and gas and pipeline companies, have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.
We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements, allows us to compete more effectively. This includes having access to both NGL and natural gas markets to allow for flexibility in our gathering and processing in addition to having critical connections to a strong sponsor and key market outlets for NGLs and natural gas. Our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of our resource plays. The strategic location of our assets, including those connected to MPC, and the long-term nature of many of our contracts also provide a significant competitive advantage.
INSURANCE
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and business interruption. We are insured under MPC and other third-party insurance policies. The MPC policies are subject to shared deductibles.
SEASONALITY
The volume of crude oil and refined products transported and stored utilizing our assets is affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. The majority of effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments.
In our G&P segment we experience minimal impacts from seasonal fluctuations which impact the demand for natural gas and NGLs and the related commodity prices caused by various factors including variations in weather patterns from year to year. We are able to manage the seasonality impacts through the execution of our marketing strategy and via our storage capabilities. Overall, our exposure to the seasonality fluctuations is declining due to our growth in fee-based business.
REGULATORY MATTERS
Our operations are subject to numerous laws and regulations, including those relating to the protection of the environment. Such laws and regulations include, among others, the Interstate Commerce Act (“ICA”), the Natural Gas Act (“NGA”), the Clean Water Act (“CWA”) with respect to water discharges, the Clean Air Act (“CAA”) with respect to air emissions, 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. For additional information regarding regulatory risks, see Item 1A. Risk Factors.
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Pipeline Regulations
Liquids Pipelines
Some of our existing pipelines are considered interstate common carrier pipelines subject to regulation by the Federal Energy Regulatory Commission (“FERC”) under the Interstate Commerce Act (the “ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and FERC regulations require that tariff rates for oil pipelines, a category that includes crude oil and petroleum product pipelines, be just and reasonable and the terms and conditions of service must not be unduly discriminatory. The ICA permits interested persons to challenge newly proposed tariff rates or terms and conditions of service, or any change to tariff rates or terms and conditions of service, and authorizes FERC to suspend the effectiveness of such proposal or change for a period of time to investigate. If, upon completion of an investigation, FERC finds that the new or changed service or rate is unlawful, it is authorized to require the carrier to refund the revenues in excess of the prior tariff collected during the pendency of the investigation. An interested person may also challenge existing terms and conditions of service or rates and FERC may order a carrier to change its terms and conditions of service or rates prospectively. Upon an appropriate showing, a shipper may also obtain reparations for damages sustained during the two years prior to the filing of a complaint.
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.
FERC permits regulated oil pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. A carrier must, as a general rule, utilize the indexing methodology to change its rates. Cost-of-service ratemaking, market-based rates and settlement rates are alternatives to the indexing approach and may be used in certain specified circumstances to change rates.
Intrastate services provided by certain of our liquids pipelines are subject to regulation by state regulatory authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. Not all state regulatory bodies allow for changes based on an index method similar to that used by FERC. In those instances, rates are generally changed only through a rate case process. The state regulators could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could, if permitted under state law, require the payment of refunds to shippers.
FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates are not the subject of a protest or a complaint by a shipper. FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in our tariff rate level.
Natural Gas Pipelines
Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Under the NGA, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable, or unduly discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. 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). Any successful complaint or protest related to our services or facilities could have an adverse impact on our revenues.
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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.
Natural Gas Gathering
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. We own a number of facilities that we believe qualify as production and gathering facilities not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, potentially provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC reporting requirements.
In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, non-discriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.
Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Energy Policy Act of 2005
Under the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”) and related regulations, it is 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. EPAct 2005 gives the FERC civil penalty authority to impose penalties for certain violations of up to approximately $1.3 million per day for each violation, subject to FERC’s annual inflation adjustment. FERC also has the authority to order disgorgement of profits from transactions deemed to violate the NGA and the EPAct 2005.
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
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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.
PHMSA Regulation
We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979 (“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, 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, 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 increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. Additionally, we are subject to the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, which required PHMSA to develop underground gas storage standards within two years and provided PHMSA with significant new authority to issue industry-wide emergency orders if an unsafe condition or practices results in an imminent hazard.
The DOT has delegated its authority under these statutes to the PHMSA, which administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of natural gas by pipeline (49 C.F.R. Part 192), as well as hazardous liquids by pipeline (49 C.F.R. Part 195), including regulations for the design and construction of new pipelines or those that have been relocated, replaced or otherwise changed (Subparts C and D of 49 C.F.R., Part 195); pressure testing of new pipelines (Subpart E of 49 C.F.R. Part 195); operation and maintenance of pipelines, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs and managing the operation of pipeline control rooms (Subpart F of 49 C.F.R. Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 C.F.R. Part 195); and integrity management requirements for pipelines in HCAs (49 C.F.R. 195.452). PHMSA has undertaken a number of initiatives to reevaluate its pipeline safety regulations. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.
Notwithstanding the foregoing, PHMSA and one or more state regulators have, in isolated circumstances in the past, sought to expand the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities in order to assess compliance with hazardous liquids pipeline safety requirements. If any of these actions were made broadly enforceable as part of a rule-making process or codified into law, they could result in additional capital costs, possible operational delays and increased costs of operation.
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Environmental and Other Regulations
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. Generally speaking, however, the trend in environmental law is to place more restrictions and limitations on activities that may be perceived to adversely affect the environment, which may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our permitting applications, or cause us to become involved in time consuming and costly litigation. Thus, there can be no assurance as to the amount or timing of future expenditures for compliance with environmental laws and regulations, permits and permitting requirements or remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements may result in increased compliance and mitigation costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, and could have a material adverse effect on our business, financial condition, results of operations and cash flow. We may not be able to recover some or any of these costs from insurance. Such revised or additional environmental requirements may also result in substantially increased costs and material delays in the construction of new facilities or expansion of our existing facilities, which may materially impact our ability to meet our construction obligations with our producer customers.
Remediation
A comprehensive framework of environmental laws and regulations governs our operations as they relate to the possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and surface water and measures taken to mitigate pollution into the environment. CERCLA, also known as the “Superfund” law, as well as comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment and for restoration costs and damages to natural resources. RCRA and similar state laws may also impose liability for removing or remediating releases of hazardous or non-hazardous wastes from impacted properties.
We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering, processing and transportation, for NGL fractionation, for the storage, gathering and transportation of crude oil, or for the storage and transportation of refined products. During the normal course of operation, whether by us or prior owners or operators, releases of petroleum hydrocarbons or other non-hazardous or hazardous wastes have or may have occurred. We could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination, or to perform remedial operations
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to prevent future contamination. We do not believe that we have any current material liability for cleanup costs under such laws or for third-party claims.
Hazardous and Solid Wastes
We may incur liability under RCRA, and comparable or more stringent state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous wastes. In the course of our operations, we generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. It is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and disposal requirements.
Water
We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. In addition, we are regulated under OPA-90, which, among other things, requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. OPA-90 also requires the responsible company to pay resulting removal costs and damages and provides for civil penalties and criminal sanctions for violations of its provisions. We operate tank vessels and facilities from which spills of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures plans for all facilities subject to such requirements. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.
Construction or maintenance of our plants, compressor stations, pipelines, barge docks and storage facilities may impact wetlands or other surface water bodies, which are also regulated under the CWA by the EPA, the United States Army Corps of Engineers and state water quality agencies. Regulatory requirements governing wetlands and other surface water bodies (including associated mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the CWA and analogous state laws. However, there is no assurance that we will not incur material increases in our operating costs or delays in the construction or expansion of our facilities because of future developments, the implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other causes.
In April 2020, the U.S. District Court in Montana vacated Nationwide Permit 12 (“NWP 12”), which authorizes the placement of fill material in “waters of the United States” for utility line activities as long as certain best management practices are implemented. The decision was ultimately appealed to the United States Supreme Court, which partially reversed the district court’s decision, temporarily reinstating NWP 12 for all projects except the Keystone XL oil pipeline. The United States Army Corps of Engineers subsequently reissued its nationwide permit authorizations on January 13, 2021, by dividing the NWP that authorizes utility line activities (NWP 12) into three separate NWPs that address the differences in how different utility line projects are constructed, the substances they convey, and the different standards and best management practices that help ensure those NWPs authorize only those activities that have no more than minimal adverse environmental effects. A challenge of the 2021 authorization is currently pending before the U.S. District Court in Montana and the plaintiffs request the court vacate and remand the 2021 authorization. Also, a petition has been filed with the United States Army Corps of Engineers asking it to revoke the 2021 authorization. The Biden Administration could repeal or replace the 2021 authorization in a subsequent rulemaking. Repeal, vacation, revocation or replacement of the 2021 authorization could impact pipeline construction and maintenance activities.
As part of our emergency response activities, we have used aqueous film forming foam (“AFFF”) containing per- and polyfluoroalkyl substances (“PFAS”) chemicals as a vapor and fire suppressant. At this time, AFFFs containing PFAS are the only proven foams that can prevent and control a flammable petroleum-based liquid fire involving a large storage tank or tank containment area. In May 2016, the EPA issued lifetime health advisory levels (“HALs”) and health effects support documents for two PFAS substances - Perfluorooctanoic Acid (“PFOA”) and Perfluorooctane Sulfonate (“PFOS”). Then, in February 2019, EPA issued a PFAS Action Plan identifying actions the
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EPA is planning to take to study and regulate various PFAS chemicals. The EPA identified that it would evaluate, among other actions, (1) proposing national drinking water standards for PFOA and PFOS, (2) develop cleanup recommendations for PFOA and PFOS, (3) evaluate listing PFOA and PFOS as hazardous substances under CERCLA, and (4) conduct toxicity assessments for other PFAS chemicals. In October 2021, EPA updated the 2019 PFAS Action Plan. The Biden Administration has drafted a proposed rule that would designate variants of PFAS as CERCLA hazardous substances. Additional PFAS regulation could include the designation of PFAS as a RCRA hazardous waste and/or the establishment of national drinking water standards. Congress may also take further action to regulate PFAS. We cannot currently predict the impact of potential statutes or regulations on our operations or remediation costs. In addition, many states are actively proposing and adopting legislation and regulations relating to the use of AFFFs containing PFAS. Additionally, many states are using the EPA HALs for PFOS and PFOA and some states are adopting and proposing state-specific drinking water and cleanup standards for various PFAS, including PFOS and PFOA. We cannot currently predict the impact of these regulations on our liquidity, financial position, or results of operations.
Air Emissions
The Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or 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 2021, the EPA announced it is reconsidering the National Ambient Air Quality Standards (“NAAQS”) for ozone and particulate matter. Lowering of the NAAQS and subsequent designation as a nonattainment area could result in increased costs associated with, or result in cancellation or delay of, capital projects at our or our customers’ facilities, or could require emission reductions that could result in increased costs to us or our customers. We cannot predict the effects of the various state implementation plan requirements at this time.
In 2007 the California Air Resources Board (“CARB”) adopted the At-Berth Regulation to control airborne emissions from ocean-going vessels at berth but excluded tanker vessels due to safety and technological challenges for stack emission capture on vessels with hazardous cargo, which challenges still exist today. CARB amended the regulation in August 2020, to include maximum emission rates from auxiliary engines and boilers used to unload tanker vessels at berth. The obligation to meet the emission rates applies to both a vessel and the terminal where it is unloading. The emission rates apply to vessels unloading at terminals at the Port of Long Beach and the Port of Los Angeles beginning January 1, 2025, and at all other terminals beginning January 1, 2027. The amended regulation has been challenged in court and could impact the compliance timeline. Compliance with the regulation is expected to increase our costs at affected facilities.
Climate Change
We believe it is likely that the scientific and political attention to greenhouse gas emissions, climate change and climate adaptation will continue, with the potential for further regulations that could affect our operations. Currently, legislative and regulatory measures to address greenhouse gas emissions are in various phases of review, discussion or implementation. Reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities, (iii) capture the emissions from our facilities and (iv) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments.
Congress has from time to time considered legislation to reduce emissions of greenhouse gases (“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
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electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. In November 2021, the EPA proposed regulations that would expand and strengthen methane emission reductions from new, modified and reconstructed oil and natural gas sources. 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. The Council on Environmental Quality has sought comment on the extent to which an environmental assessment must consider direct and indirect greenhouse gas emissions from a new project. Uncertainty related to the environmental assessment can result in delay and increased costs in completing new projects.
Endangered Species Act and Migratory Bird Treaty Act Considerations
The federal Endangered Species Act (“ESA”) and analogous state laws regulate activities that may affect endangered or threatened species, including their habitats. If protected species are located in areas where we propose to construct new gathering or transportation pipelines, processing or fractionation facilities, or other infrastructure, such work could be prohibited or delayed in certain of those locations or during certain times, when our operations could result in a taking of the species or destroy or adversely modify critical habitat that has been designated for the species. We also may be obligated to develop plans to avoid potential takings of protected species and provide mitigation to offset the effects of any unavoidable impacts, the implementation of which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increases our construction and mitigation costs or restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to a listed species and could result in alleged takings under the ESA, exposing MPLX to civil or criminal enforcement actions and fines or penalties. The existence of threatened or endangered species in areas where we conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from species protection measures or could result in delays in, or prohibit, the construction of our facilities or limit our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.
The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without authorization. If there is the potential to adversely affect migratory birds as a result of our operations or construction activities, we may be required to seek authorization to conduct those operations or construction activities, which may result in specified operating or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an adverse impact on our ability to provide timely gathering, processing or fractionation services to our exploration and production customers.
Safety Matters
We are subject to oversight pursuant to the federal Occupational Safety and Health Act (“OSH Act”), as amended, as well as comparable state statutes that regulate the protection of the health and safety of workers. We believe that we have conducted our operations in substantial compliance with regulations promulgated pursuant to the OSH Act, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.
We are also subject at regulated facilities to the Occupational Safety and Health Administration’s Process Safety Management and the EPA’s Risk Management Program requirements, which are intended to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. The application of these regulations can result in increased compliance expenditures.
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In general, we expect industry and regulatory safety standards to become more stringent 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.
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. 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.
Marine Transportation
Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act, state laws and certain international conventions, as well as numerous environmental regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels.
Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage law that restricts domestic marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones Act for our vessels. The loss of Jones Act status could have a significant negative effect on our marine transportation business. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the USCG, and the application of United States labor and tax laws increases the cost of United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that is not subject to the same United States government-imposed burdens.
The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is necessary in the interest of national defense. For example, the Secretary has waived the Jones Act for limited periods of time and in limited areas following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act can result in increased competition from foreign tank vessel operators, which could negatively impact our marine transportation business.
Security
Certain of our facilities are 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.” 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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Tribal Lands
Various federal agencies, including the EPA and the Department of the Interior, along with certain Native American tribes, promulgate and enforce regulations pertaining to oil and gas operations on Native American tribal lands where we operate. These regulations include such matters as lease provisions, drilling and production requirements, and standards to protect environmental quality and cultural resources. In addition, each Native American tribe is a sovereign nation having the right to enforce certain laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These laws and regulations may increase our costs of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct, our operations on such lands.
HUMAN CAPITAL
We are managed and operated by the board of directors and executive officers of MPLX GP LLC (“MPLX GP”), our general partner and a wholly owned subsidiary of MPC. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are directly employed by affiliates of our general partner. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.
MPC believes its employees are its greatest asset of strength, and the culture reflects the quality of individuals across its workforce. Its collaborative efforts to foster an inclusive environment, provide broad-based development and mentorship opportunities, recognize and reward accomplishments, and offer benefits that support the well-being of its employees and their families contribute to increased engagement and fulfilling careers. Empowering people and prioritizing accountability also are key components for developing a high-performing culture, which is critical to achieving our strategic vision.
Employee Profile
As of December 31, 2021, our general partner and its affiliates, have approximately 5,836 full-time employees that provide services to us under our employee services agreements.
Talent Management
Executing MPC’s strategic vision requires that it attracts and retains the best talent. Recruiting and retention success requires that it effectively nurtures new employees, providing opportunities for long-term engagement and career advancement. MPC must also appropriately reward high-performers and offer competitive benefits. MPC’s Talent Acquisition team consists of three segments: Executive Recruiting, Experienced Recruiting and University Recruiting. The specialization within each group allows MPC to specifically address its broad range of current and future talent needs, as well as devote time and attention to candidates during the hiring process. MPC values diverse perspectives in the workforce, and accordingly seeks candidates with a variety of backgrounds and experience. MPC’s primary source of full-time, entry-level new hires is its intern/co-op program. Through its university recruiters, MPC offers college students who have completed their freshman year the opportunity to participate in its hands-on programs focused in areas of finance and accounting, marketing, engineering and IT.
MPC provides a broad range of leadership training opportunities to support the development of leaders at all levels. Those programs, which are offered across the organization, are a blended approach of business and leadership content, with many featuring external faculty. MPC utilizes various learning modalities, such as visual, audio, print, tactile, interactive, kinesthetic, experiential and leader-teaching-leader to address and engage different learning styles. MPC believes networking and access to executives are key leadership success factors, and MPC incorporates these opportunities into all of its programs.
Compensation and Benefits
To ensure MPC is offering competitive pay packages in its recruitment and retention efforts, it annually benchmarks compensation, including base salaries, bonus levels and equity targets. MPC’s annual bonus program is a critical component of its compensation, as it provides individual rewards for achievement against preset financial and ESG goals, encouraging a sense of employee ownership. Employees in officer-level pay grades, as well as senior
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leaders and most mid-level leaders, are eligible to receive long-term equity incentive awards as part of their compensation.
MPC offers comprehensive benefits, including medical, dental and vision insurance for employees, their spouses or domestic partners, and their dependents. MPC also provides retirement programs, life insurance, education assistance, family assistance, short-term disability and paid vacation and sick time. In addition, MPC provides generous paid parental leave benefits for birth mothers and nonbirth parents; and, parents who both work for MPC are each eligible for the benefit. Further, MPC has a substantial accrual cap for vacation banks and also award a significant number of college and trade school scholarships to the high school senior children of employees through the Marathon Petroleum Scholars Program. Both full-time and part-time employees are eligible for these benefits.
Inclusion
MPC's company-wide Diversity, Equity and Inclusion ("DE&I") program is guided by a dedicated DE&I team led by our Vice President Talent Acquisition and Diversity, Equity & Inclusion and supported by leadership company-wide. The program is based on a four-pillar DE&I strategy of building awareness, increasing representation, ensuring success, and measurement and accountability. MPC has employee networks focusing on six populations: Asian, Black, Hispanic, Veterans, Women and LGBTQ+. MPC’s employee networks have approximately 60 chapters across the company and all networks encourage ally membership. This broad support extends also to leaders throughout MPC, with each employee network represented by two active executive sponsors. The sponsors form several counsels that meet regularly to share updates, gain alignment, build deeper connections across networks and pursue collaboration ideas. The employee networks not only provide opportunities for employees to make meaningful and supportive connections, but they also serve a significant role in MPC’s DE&I strategy.
Safety
MPC is committed to safe operations to protect the health and safety of its employees, contractors and communities. MPC’s commitment to safe operations is reflected in its safety systems design, its well-maintained equipment and by learning from its incidents. Part of MPC’s effort to promote safety includes the Operational Excellence Management System, which expands on the RC14001® scope, incorporates a Plan-Do-Check-Act continual improvement cycle, and aligns with ISO 9001, incorporating quality and an increased stakeholder and process focus. Together, these components of MPC’s safety management system provide it with a comprehensive approach to managing risks and preventing incidents, illnesses and fatalities. Additionally, MPC’s annual cash bonus program metrics includes several employee, process and environmental safety metrics.
In 2021, MPC continued to run its critical operations and facilities safely through the ongoing pandemic. In addition to COVID-19 protection measures implemented in 2020 (e.g., masking, social distancing, barriers, etc.), MPC promoted vaccinations through education campaigns and onsite clinics. Thousands of employees were inoculated at vaccine points of distribution set up onsite or through collaborative efforts with local public health clinics. As a result of these measures, MPC was able to welcome most non-essential employees back into the workplace in the spring of 2021. MPC continues to monitor the situation and adapt its practices as appropriate.
AVAILABLE INFORMATION
General information about MPLX LP and its general partner, MPLX GP LLC, including Governance Principles, Audit Committee Charter, Conflicts Committee Charter and Certificate of Limited Partnership, can be found at www.mplx.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available in this same location.
MPLX LP uses its website, www.mplx.com, as a channel for routine distribution of important information, including news releases, analyst presentations and financial information. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC, or on the SEC’s website at www.sec.gov. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.
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Item 1A. Risk Factors
You should carefully consider each of the following risks and all the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Although the risks are organized by headings, and each risk is discussed separately, many are interrelated. Our business, financial condition, results of operations and cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline. You should not interpret the disclosure of any risk factor to imply that the risk has not already materialized.
Summary of Risk Factors
We have in the past been adversely affected by certain of, and may in the future be adversely affected by, the following:
•the COVID-19 pandemic;
•a significant decrease in oil and natural gas production in our areas of operation;
•inflation;
•challenges in accurately estimating expected production volumes of our producer customers;
•our dependence on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas we process, and the NGLs we fractionate and stabilize at our facilities;
•our ability to retain existing customers or acquire new customers;
•our ability to increase fees enough to cover costs incurred under our gathering, processing, transmission, transportation, fractionation, stabilization and storage agreements;
•unplanned maintenance of the United States (“U.S.”) inland waterway infrastructure;
•interruptions in operations at any of our facilities or those of our customers, including MPC;
•problems affecting our information technology systems and those of our third-party business partners and service providers;
•in our joint ventures, our lack of sole decision-making authority, our reliance on our joint venture partners’ financial condition and disputes between us and our joint venture partners;
•terrorist attacks or other targeted operational disruptions aimed at our facilities or that impact our customers or the markets we serve;
•increases to our maintenance or repair costs;
•severe weather events and other climate conditions;
•insufficient cash from operations after the establishment of cash reserves and payment of our expenses to enable us to pay the intended quarterly distribution to our unitholders;
•our substantial debt and other financial obligations;
•increases in interest rates;
•uncertainty relating to the calculation of LIBOR and replacement reference rates;
•our exposure to the credit risks of our key customers and derivative counterparties;
•negative effects of our commodity derivative activities;
•uninsured losses;
•future costs relating to evolving environmental or other laws or regulations;
•increased regulation of hydraulic fracturing;
•climate-related and greenhouse gas emission regulation;
•climate-related litigation;
•societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels;
•market deterioration prior to the completion of large capital projects;
•increasing attention to ESG matters;
•federal and tribal approvals, regulations and lawsuits relating to our facilities that are located on Native American tribal lands;
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•our ability to maintain or obtain real property rights required for our business;
•the consequences resulting from foreign investment in us or our general partner exceeding certain levels;
•federal or state rate and service regulation or rate-making policies;
•costs and liabilities resulting from performance of pipeline integrity programs and related repairs;
•future impairments;
•difficulties in making strategic acquisitions on economically acceptable terms from MPC or third parties;
•integration risks from significant future acquisitions;
•the failure by MPC to satisfy its obligations to us, or a significant reduction in volumes transported through our facilities or stored at our storage assets;
•MPC materially suspending, reducing or terminating its obligations under its agreements with us;
•MPC’s level of indebtedness or credit ratings;
•various tax risks inherent in our master limited partnership structure, including the potential for unexpected tax liabilities for us or our unitholders, more burdensome tax filing requirements and future legislative changes to the expected tax treatment of an investment in us;
•MPC’s conflicts of interest with us, its limited duties to us and our unitholders, and its potential favoring of its interests over our interests and the interests of our unitholders;
•the requirements and restrictions arising under our Sixth Amended and Restated Agreement of Limited Partnership, dated as of February 1, 2021 (“Partnership Agreement”), including the requirement that we distribute all of our available cash, limitations on our general partner’s duties, limited unitholder voting rights, and limited unitholder recourse in the event unitholders are dissatisfied with our operations;
•cost reimbursements and fees paid to our general partner and its affiliates, which in certain circumstances are subject to our general partner’s sole discretion;
•control of our general partner being transferred to a third party without unitholder consent;
•the issuance of additional units resulting in the dilution of limited unitholder interests, which issuances may be made without unitholder approval;
•the sale of units - and the adverse impact on the trading price of the common units which might result from such sale - by MPC of the units it holds in public or private markets, and such sales could have an adverse impact on the trading price of the common units;
•affiliates of our general partner, including MPC, competing with us, and neither our general partner nor its affiliates having any obligation to present business opportunities to us;
•our general partner having a limited call right that may require unitholders to sell common units at an undesirable time or price;
•a unitholder’s liability not being limited if a court finds that unitholder action constitutes control of our business;
•unitholders may have to repay distributions that were wrongfully distributed to them;
•the NYSE not requiring a publicly traded limited partnership like us to comply with certain of its corporate governance requirements; and
•the Court of Chancery of the State of Delaware being, to the extent permitted by law, the sole and exclusive forum for substantially all disputes between us and our limited partners.
Business and Operational Risks
The COVID-19 pandemic has had, and may continue to have, a material and adverse effect on our and our customers’ business and on general economic, financial and business conditions.
The COVID-19 pandemic and existing COVID-19 mitigation measures continue to have adverse effects on global travel and economic activity and, consequently, demand for the petroleum products that we transport and store. Significant uncertainty remains as to the extent to which further resurgences in the virus, the emergence of new variants and waning vaccine effectiveness may spur future actions by individuals, governments and the private sector to stem the spread of the virus.
The extent to which the COVID-19 pandemic continues to impact global economic conditions, our business and the business of our customers, suppliers and other counterparties, will depend largely on future developments that
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remain uncertain and cannot be predicted, such as the length and severity of the pandemic; the social, economic and epidemiological effects of COVID-19 mitigation measures; the extent to which individuals acquire and retain immunity; emerging virus variants and how those new variants of the disease affect the human body; and general economic conditions. New or additional mitigation measures required by national, state or local governments, such as vaccine or testing mandates, may result in increased operating costs, increased employee attrition and difficulty in securing future workforce needs, and may adversely affect discretionary and business travel.
Additionally, the continuation of the pandemic could precipitate or aggravate the other risks identified in this Form 10-K, which in turn could further materially and adversely affect our business, financial condition and results of operations, including in ways not currently known or considered by us to present significant risks.
A significant decrease in oil and natural gas production in our areas of operation may adversely affect our business, financial condition, results of operation and cash available for distribution.
A significant portion of our operations is dependent on the continued availability of natural gas and crude oil production. The production from oil and natural gas reserves and wells owned by our producer customers will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful drilling activity near our facilities, our ability to compete for volumes from successful new wells and our ability to expand our system capacity as needed.
We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by demand, prevailing and projected energy prices, drilling costs, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Reductions in exploration or production activity in our areas of operations could lead to reduced throughput on our pipelines and utilization rates of our facilities.
Decreases in energy prices can decrease drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend upon factors beyond our control, including global and local demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices could result in producers deciding to limit their oil and gas drilling operations, which could substantially delay the production and delivery of volumes of oil, natural gas and NGLs to our facilities and adversely affect our revenues and cash available for distribution.
This impact may also be exacerbated due to the extent of our commodity-based contracts, which are more directly impacted by changes in natural gas and NGL prices than our fee-based contracts due to frac spread exposure and may result in operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In addition, our purchase and resale of gas and NGLs in the ordinary course exposes us to significant risk of volatility in natural gas or NGL prices due to the potential difference in the time of the purchases and sales and the potential difference in the price associated with each transaction, and direct exposure may also occur naturally as a result of our production processes. The significant volatility in natural gas, NGL and oil prices could adversely impact our unit price, thereby increasing our distribution yield and cost of capital. Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy our obligations to our customers, and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.
We may be negatively impacted by inflation.
Increases in inflation may have an adverse effect on us. Current and future inflationary effects may be driven by, among other things, supply chain disruptions and governmental stimulus or fiscal policies. Continuing increases in inflation could impact the commodity markets generally, the overall demand for our products and services, our costs for labor, material and services and the margins we are able to realize on our products, all of which could have an adverse impact on our business, financial position, results of operations and cash flows. Inflation may also result
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in higher interest rates, which in turn would result in higher interest expense related to our variable rate indebtedness and any borrowings we undertake to refinance existing fixed rate indebtedness.
We may not always be able to accurately estimate expected production volumes of our producer customers; therefore, volumes we service in the future could be less than we anticipate.
We may not be able to accurately estimate expected production volumes of our producer customers. Furthermore, we may have only limited oil, natural gas, NGL or refined product supplies committed to any new facility prior to its construction. We may construct facilities to capture anticipated future growth in production or satisfy anticipated market demand which does not materialize, the facilities may not operate as planned or may not be used at all. In order to attract additional oil, natural gas, NGL or refined product supplies from a customer, we may be required to order equipment and facilities, obtain rights of way or other land rights or otherwise commence construction activities for facilities that will be required to serve such customer’s additional supplies prior to executing agreements with the customer. If such agreements are not executed, we may be unable to recover such costs and expenses. Additionally, new facilities may not be able to attract enough oil, natural gas, NGLs or refined products to achieve our expected investment return. Alternatively, oil, natural gas, NGL or refined product supplies committed to facilities under construction may be delivered prior to completion of such facilities, or we may otherwise have unexpected increases in volumes that could adversely affect our ability to expand our facilities. In such event, we may be required to temporarily utilize third-party facilities for such oil, natural gas, NGLs or refined products, which may increase our operating costs and reduce our cash available for distribution.
We depend on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas we process, and the NGLs we fractionate and stabilize at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.
A significant portion of our supply of oil, natural gas, NGLs and refined products comes from a limited number of key producers/suppliers, who may be under no obligation to deliver a specific volume to our facilities. If any of these significant suppliers, or a significant number of smaller producers, were to decrease the supply of oil, natural gas, NGLs or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural gas, NGLs or refined products to our facilities or we rely on other third parties to deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or the third parties modify the flow of natural gas or NGLs on those systems away from our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow.
We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.
A significant portion of our business comes from a limited number of key customers. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines and fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new customers that we cannot provide. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services.
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As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability.
The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.
Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events outside our control, and in some cases, certain of those agreements may be terminated in their entirety if the duration of such events exceeds a specified period of time. If the escalation of fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if third parties suspend or terminate their contracts with us, our financial results would suffer.
The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our operations.
Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by approximately 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the locks, planned and unplanned maintenance may create more frequent outages, resulting in delays and additional operating expenses. Part of the costs for new construction and major rehabilitation of locks and dams is funded by marine transportation companies through taxes and the other portion is funded by general federal tax revenues. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products to our customers on a timely basis. Furthermore, any additional user taxes that may be imposed in the future to fund infrastructure improvements would increase our operating expenses.
Our operations are subject to business interruptions and casualty losses.
Our operations are subject to business interruptions, such as unplanned maintenance, explosions, fires, pipeline releases, power outages, severe weather, labor disputes, acts of terrorism or other natural or man-made disasters. These types of incidents adversely affect us. Our customers’ operations, including MPC’s refining operations, are subject to similar risks.
These types of incidents adversely affect our operations and may result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses. We and our customers have experienced certain of these incidents in the past. For assets located near populated areas, the level of damage resulting from these risks could be greater. Due to the nature of our operations, certain interruptions could impact operations in other regions.
Our marine transportation business, in particular, is subject to weather conditions. Adverse weather conditions such as high or low water on the inland waterway systems, fog and ice, tropical storms, hurricanes and tsunamis on both the inland waterway systems and throughout the U.S. coastal waters can impair the operating efficiencies of the marine fleet. Such adverse weather conditions can cause a delay, diversion or postponement of shipments of products and are beyond our control.
In addition, we operate in and adjacent to environmentally sensitive waters where tanker, pipeline, rail car and refined product transportation and storage operations are closely regulated by federal, state and local agencies and monitored by environmental interest groups. Transportation and storage of crude oil, other feedstocks and refined
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products over and adjacent to water involves inherent risk and subjects us to the provisions of the OPA-90 and state laws in U.S. coastal and Great Lakes states and states bordering inland waterways on which we operate. If we are unable to promptly and adequately contain any accident or discharge involving tankers, pipelines, rail cars or above ground storage tanks transporting or storing crude oil, other feedstocks or refined products, we may be subject to substantial liability. In addition, the service providers contracted to aid us in a discharge response may be unavailable due to weather conditions, governmental regulations or other local or global events.
The construction and operation of certain of our facilities may be impacted by surface or subsurface mining operations by one or more third parties, which could adversely impact our construction activities or cause subsidence or other damage to our facilities. In such event, our construction may be prevented or delayed, or the costs and time increased, or our operations at such facilities may be impaired or interrupted, and we may not be able to recover the costs incurred for delays or to relocate or repair our facilities from such third parties.
We are increasingly dependent on the performance of our information technology systems and those of our third-party business partners and service providers.
We are increasingly dependent on our information technology systems and those of our third-party business partners and service providers for the safe and effective operation of our business. We rely on such systems to process, transmit and store electronic information, including financial records and personally identifiable information such as employee, customer and investor data, and to manage or support a variety of business processes, including our supply chain, pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions.
Our systems (and those of our third-party business partners and service providers) are subject to numerous and evolving cybersecurity threats and attacks, including ransomware and other malware, and phishing and social engineering schemes, which can compromise our ability to operate, and the confidentiality, availability, and integrity of data in our systems or those of our third-party business partners and service providers. These and other cybersecurity threats may originate with criminal attackers, state-sponsored actors, or employee error or malfeasance. Because the techniques used to obtain unauthorized access, or to disable or degrade systems continuously evolve and have become increasingly complex and sophisticated, and can remain undetected for a period of time despite efforts to detect and respond in a timely manner, we (and our third-party business partners and service providers) are subject to the risk of cyberattacks.
Our cybersecurity and infrastructure protection technologies, disaster recovery plans and systems, employee training and vendor risk management may not be sufficient to defend us against all unauthorized attempts to access our information or impact our systems. We and our third-party vendors and service providers have been and may in the future be subject to cybersecurity events of varying degrees. To date, the impacts of prior events have not had a material adverse effect on us.
Cybersecurity events involving our information technology systems or those of our third-party business partners and service providers can result in theft, destruction, loss, misappropriation or release of confidential financial data, regulated personally identifiable information, intellectual property and other information; give rise to remediation or other expenses; result in litigation, claims and increased regulatory review or scrutiny; reduce our customers’ willingness to do business with us; disrupt our operations and the services we provide to customers; and subject us to litigation and legal liability under international, U.S. federal and state laws. Any of such results could have a material adverse effect on our reputation, business, financial condition, results of operations and cash flows.
Our investments in joint ventures could be adversely affected by our reliance on our joint venture partners and their financial condition, and our joint venture partners may have interests or goals that are inconsistent with ours.
We conduct some of our operations through joint ventures in which we share control over certain economic and business interests with our joint venture partners. Our joint venture partners may have economic, business or legal interests or goals that are inconsistent with our goals and interests or may be unable to meet their obligations. Failure by us, or an entity in which we have an interest, to adequately manage the risks associated with any acquisitions or joint ventures could have a material adverse effect on the financial condition or results of operations of our joint ventures and adversely affect our reputation, business, financial condition, results of operations and cash flows.
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Terrorist attacks or other targeted operational disruptions may affect our facilities or those of our customers and suppliers.
Refining, gathering and processing, pipeline and terminal infrastructure, and other energy assets, may be the subject of terrorist attacks or other targeted operational disruptions. Any terrorist attack or targeted disruption of our operations, those of our customers or, in some cases, those of other energy industry participants, could have a material and adverse effect on our business. Similarly, any similar event that severely disrupts the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.
Many of our assets have been in service for many years and, as a result, our maintenance or repair costs may increase in the future.
Our pipelines, terminals, fractionator and storage assets are generally long-lived assets, and many of them have been in service for many years. The age and condition of our assets could result in increased maintenance or repair expenditures in the future. Any significant increase in these expenditures could adversely affect our results of operations, financial position or cash flows, as well as our ability to make cash distributions to our unitholders.
Severe weather events and other climate conditions may adversely affect our and our customers’ facilities and ongoing operations.
Our and our customers’ facilities are subject to acute physical risks, such as floods, hurricane-force winds, wildfires and winter storms, and chronic physical risks, such as sea-level rise or water shortages. For example, in 2021, MPC’s Galveston Bay refinery was adversely affected by Winter Storm Uri and MPC’s Garyville refinery was adversely affected by Hurricane Ida. The occurrence of these and similar events have had, and may in the future have, an adverse effect on our assets and operations. We have incurred and will continue to incur additional costs to protect our assets and operations from such physical risks and employ the evolving technologies and processes available to mitigate such risks. To the extent such severe weather events or other climate conditions increase in frequency and severity, we may be required to modify operations and incur costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Financial Risks
We may not have sufficient cash from operations after the establishment of cash reserves and payment of our expenses, including cost reimbursements to MPC and its affiliates, to enable us to pay the intended quarterly distribution to our unitholders.
The amount of cash we can distribute to our common unitholders principally depends on the amount of cash we generate from our operations, which fluctuates from quarter to quarter based on, among other things:
•the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;
•the fees and tariff rates we charge and the margins we realize for our services and sales;
•the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;
•the level of our operating costs including repairs and maintenance;
•the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and
•prevailing economic conditions.
In addition, the actual amount of cash available for distribution also depends on other factors, some of which are beyond our control, including:
•the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC;
•our debt service requirements and other liabilities;
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•fluctuations in our working capital needs;
•our ability to borrow funds and access capital markets;
•restrictions in our joint venture agreements or agreements governing our debt;
•the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;
•the cost of acquisitions, if any; and
•the amount of cash reserves established by our general partner in its discretion, which may increase in the future and which may in turn further reduce the amount of cash available for distribution.
Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make distributions during periods when we record net losses and may not make distributions during periods when we record net income.
Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flow, and our ability to fulfill our debt obligations.
We have significant debt obligations, which totaled $20,359 million as of December 31, 2021, including amounts outstanding under our loan agreement with a wholly owned subsidiary of MPC. We may incur significant debt obligations in the future. Our indebtedness may impose various restrictions and covenants on us that could have, or the incurrence of such debt could otherwise result in, material adverse consequences, including:
•We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions, or general business purposes on favorable terms, if at all, or our cost of borrowing may increase.
•We may be at a competitive disadvantage compared to our competitors who have proportionately less debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures or a downturn in our business or the economy generally.
•If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our common units.
•The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance our operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. Our ability to comply with these covenants may be impaired from time to time if the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations.
•If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make distributions at our intended levels.
Our revolving credit facility and our loan agreement with a wholly owned subsidiary of MPC have variable interest rates. As a result, future interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future at or prior to the applicable stated maturity.
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As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make distributions at our intended levels.
The expected phase out of LIBOR could impact the interest rates paid on our variable rate indebtedness and could cause our interest expense to increase.
A portion of our borrowing capacity and outstanding indebtedness bears interest at a variable rate based on LIBOR. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR), or FCA, announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. Subsequently, on March 5, 2021, ICE Benchmark Administration Limited (the entity that calculates and publishes LIBOR), or IBA, and FCA made public statements regarding the future cessation of LIBOR. According to the FCA, IBA will permanently cease to publish each of the LIBOR settings on either December 31, 2021 or June 30, 2023. IBA did not identify any successor administrator in its announcement. The announced final publication date for 1-week and 2-month LIBOR settings and all settings for non-USD LIBOR was December 31, 2021. The announced final publication date for overnight, 1-month, 3-month, 6-month and 12-month LIBOR settings is June 30, 2023. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after such end dates, and there is considerable uncertainty regarding the publication or representativeness of LIBOR beyond such end dates. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is seeking to replace U.S. dollar LIBOR with a newly created index (the secured overnight financing rate or SOFR), calculated based on repurchase agreements backed by treasury securities.
The agreements that govern our variable rate indebtedness contain customary transition and fallback provisions in contemplation of the cessation of LIBOR. Nevertheless, at this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere may have on LIBOR, other benchmarks or floating rate indebtedness. Uncertainty as to the nature of such potential discontinuance, modification, alternative reference rates or other reforms may materially adversely affect the trading market for securities linked to such benchmarks. Furthermore, the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our floating rate indebtedness to be materially different than expected and could materially adversely impact our ability to refinance such floating rate indebtedness or raise future indebtedness on a cost-effective basis. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.
We are exposed to the credit risks of our key customers, and any material non-payment or non-performance by our key customers could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. This risk is further heightened during sustained periods of declines of natural gas, NGL and oil prices. To the extent any of our customers are in financial distress or commence bankruptcy proceedings, our contracts with them, including provisions relating to dedications of production, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If a contract with a customer is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract. Any such material non-payment or non-performance could reduce our ability to make distributions to our unitholders.
We do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.
We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards such as explosions, fires, pipeline releases, cybersecurity breaches or other incidents involving our assets or operations can reduce the funds
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available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.
Legal and Regulatory Risks
We expect to continue to incur substantial capital expenditures and operating costs to meet the requirements of evolving environmental or other laws or regulations. Future environmental laws and regulations may impact our current business plans and reduce demand for our products and services.
Our business is subject to numerous environmental laws and regulations. These laws and regulations continue to increase in both number and complexity and affect our business. Laws and regulations expected to become more stringent relate to the following:
•the emission or discharge of materials into the environment;
•solid and hazardous waste management;
•the regulatory classification of materials currently or formerly used in our business;
•pollution prevention;
•greenhouse gas emissions;
•climate change;
•public and employee safety and health;
•permitting;
•inherently safer technology; and
•facility security.
The specific impact of laws and regulations, and their enforcement, on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas and production processes and subsequent judicial interpretation of such laws and regulations. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations. We may also face liability for personal injury, property damage, natural resource damage or clean-up costs due to alleged contamination and/or exposure to chemicals such as benzene and MTBE. There is also increased regulatory interest in PFAS, which we expect will lead to increased monitoring obligations and potential liability related thereto. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.
Increased regulation of hydraulic fracturing and other oil and gas production activities could result in reductions or delays in U.S. production of crude oil and natural gas, which could adversely affect our results of operations and financial condition.
While we do not conduct hydraulic fracturing operations, we do provide gathering, processing and fractionation services with respect to natural gas and natural gas liquids produced by our customers as a result of such operations. A range of federal, state and local laws and regulations currently govern or, in some cases, prohibit, hydraulic fracturing in some jurisdictions. Stricter laws, regulations and permitting processes may be enacted in the future. If federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing or other oil and gas production activities are enacted or expanded, such efforts could impede oil and gas production, increase producers’ cost of compliance, and result in reduced volumes available for our midstream assets to gather, process and fractionate.
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Climate change and greenhouse gas emission regulation could affect our operations, energy consumption patterns and regulatory obligations, any of which could affect our results of operations and financial condition.
Currently, multiple legislative and regulatory measures to address greenhouse gas (including carbon dioxide, methane and nitrous oxides) and other emissions are in various phases of consideration, promulgation or implementation. These include actions to develop international, federal, regional or statewide programs, which could require reductions in our greenhouse gas or other emissions, establish a carbon tax and decrease the demand for refined products. Requiring reductions in these emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any emissions programs, including acquiring emission credits or allotments.
Certain municipalities have also proposed or enacted restrictions on the installation of natural gas appliances and infrastructure in new residential or commercial construction, which could affect demand for the natural gas that we transport and store.
Regional and state climate change and air emissions goals and regulatory programs are complex, subject to change and considerable uncertainty due to a number of factors including technological feasibility, legal challenges and potential changes in federal policy. Increasing concerns about climate change and carbon intensity have also resulted in societal concerns and a number of international and national measures to limit greenhouse gas emissions. Additional stricter measures and investor pressure can be expected in the future and any of these changes may have a material adverse impact on our business or financial condition.
International climate change-related efforts, such as the 2015 United Nations Conference on Climate Change, which led to the creation of the Paris Agreement, may impact the regulatory framework of states whose policies directly influence our present and future operations. Though the United States had withdrawn from the Paris Agreement, President Biden issued an executive order recommitting the United States to the Paris Agreement on January 20, 2021. President Biden also issued an Executive Order on climate change in which he announced putting the U.S. on a path to achieve net-zero carbon emissions, economy-wide, by 2050. The Executive Order also calls for the federal government to pause oil and gas leasing on federal lands, reduce methane emissions from the oil and gas sector as quickly as possible, and requires federal permitting decisions to consider the effects of greenhouse gas emissions and climate change. In a second Executive Order, President Biden reestablished a working group to develop the social cost of carbon and the social cost of methane. The social cost of carbon and social cost of methane can be used to weigh the costs and benefits of proposed regulations. A higher social cost of carbon could support more stringent greenhouse gas emission regulation.
The scope and magnitude of the changes to U.S. climate change strategy under the Biden administration and future administrations, however, remain subject to the passage of legislation and interpretation and action of federal and state regulatory bodies; therefore, the impact to our industry and operations due to greenhouse gas regulation is unknown at this time.
Energy companies are subject to increasing environmental and climate-related litigation.
Governmental and other entities in various U.S. states have filed lawsuits against various energy companies, including MPC, upon which we depend for a substantial portion of our business. The lawsuits allege damages as a result of climate change and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions. Additionally, private plaintiffs and government parties have undertaken efforts to shut down energy assets by challenging operating permits, the validity of easements or the compliance with easement conditions. For example, the Dakota Access Pipeline, in which we have a minority interest, has been subject to litigation in which plaintiffs sought a permanent shutdown of the pipeline. There remains a high degree of uncertainty regarding the ultimate outcome of these types of proceedings, as well as their potential effect on our business, financial condition, results of operation and cash flows.
We are subject to risks associated with societal and political pressures and other forms of opposition to the development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and ability to realize certain growth strategies.
We operate and develop our business with the expectation that regulations and societal sentiment will continue to enable the development, transportation and use of carbon-based fuels. However, policy decisions relating to the
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production, refining, transportation, storage and marketing of carbon-based fuels are subject to political pressures and the influence and protests of environmental and other special interest groups. Additionally, societal sentiment regarding carbon-based fuels may adversely impact our reputation and MPC’s ability to attract or retain the employees who provide services to us.
The approval process for storage and transportation projects has become increasingly challenging, due in part to state and local concerns related to pipelines, negative public perception regarding the oil and gas industry, and concerns regarding greenhouse gas emissions downstream of pipeline operations. Our expansion or construction projects may not be completed on schedule (or at all), or at the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and the surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly.
Large capital projects can take years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns.
Delays in completing capital projects or making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:
•denials of, delays in receiving, or revocations of requisite regulatory approvals or permits;
•unplanned increases in the cost of construction materials or labor, whether due to inflation or other factors;
•disruptions in transportation of components or construction materials;
•adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;
•shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;
•market-related increases in a project’s debt or equity financing costs;
•global supply chain disruptions;
•nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors; and
•delays due to citizen, state or local political or activist pressure.
Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time and we may not receive any material increases in revenues until after completion of the project, if at all.
Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our business, financial condition, results of operations and cash flows.
Increasing attention to environmental, social and governance matters may impact our business and financial results.
In recent years, increasing attention has been given to corporate activities related to environmental, social and governance (“ESG”) matters in public discourse and the investment community. A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote ESG-related change at public companies, including, but not limited to, through the investment and voting practices of investment advisers, pension funds, universities and other members of the investing community. These activities include increasing attention and demands for action related to climate change and energy transition matters, such as promoting the use of substitutes to fossil fuel products and encouraging the divestment of fossil fuel equities, as well as pressuring lenders and other financial services companies to limit or curtail activities with fossil fuel companies. If this were to continue, it could have a material adverse effect on our access to capital. Members of the investment
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community have begun to screen companies such as ours for sustainability performance, including practices related to GHG emission reduction and energy transition strategies. If we are unable to find economically viable, as well as publicly acceptable, solutions that reduce our GHG emissions, reduce GHG intensity for new and existing projects, increase our non-fossil fuel product portfolio, and/or address other ESG-related stakeholder concerns, we could experience additional costs or financial penalties, delayed or cancelled projects, or adverse unit price impacts, which could have a material and adverse effect on our business and results of operations.
Certain of our facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which can increase our costs and delay or prevent our efforts to conduct planned operations.
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands. In addition, each Native American tribe is a sovereign nation having the right to enforce laws and regulations and to grant approvals independent from federal, state and local statutes and regulations. These tribal laws and regulations include various taxes, fees, requirements to employ Native American tribal members and other conditions that apply to operators and contractors conducting operations on Native American tribal lands. Persons conducting operations on tribal lands are generally subject to the Native American tribal court system. In addition, if our relationships with any of the relevant Native American tribes were to deteriorate, we could face significant risks to our ability to continue operations on Native American tribal lands. One or more of these factors may increase our cost of doing business on Native American tribal lands and impact the viability of, or prevent or delay our ability to conduct our operations on such lands.
Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our business.
We do not own all of the land on which our assets are located, but rather obtain the rights to construct and operate such assets on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the possibility of more burdensome terms and increased costs to obtain and retain necessary land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined that we do not have valid leases, rights-of-way or other property rights. For example, a portion of the Tesoro High Plains pipeline in North Dakota remains shut down following delays in renewing a right-of-way necessary for the operation of a section of the pipeline. Any loss of or reduction in these rights, including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way agreements or permits on satisfactory terms or at all, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
If foreign investment in us or our general partner exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.
The Shipping Act of 1916 and Merchant Marine Act of 1920 (collectively, the “Maritime Laws”), generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.
Some of our natural gas, NGL, crude oil and refined product pipelines are subject to FERC’s rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.
A number of our pipelines provide interstate service that is subject to regulation by FERC. FERC prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines. FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in FERC’s approved rate methodologies, or challenges to our application of an approved methodology, could also adversely affect our rates. Additionally, shippers may protest (and FERC may investigate) the lawfulness of tariff rates. FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.
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Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.
Pipelines and operations not subject to regulation by FERC may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services and that we offer service to our shippers on a not unduly discriminatory basis. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business – Regulatory Matters as set forth in this Annual Report on Form 10-K.
We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs, and the expansion of pipeline safety laws and regulations could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.
The DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could do the most harm. The regulations require the following of operators of covered pipelines to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
•improve data collection, integration and analysis;
•repair and remediate the pipeline as necessary; and
•implement preventive and mitigating actions.
Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. The adoption of additional laws or regulations that apply more comprehensive or stringent safety standards to gas, NGL, crude oil and refined product lines or other facilities, or the expansion of regulatory inspections by regulators, could require us to install new or modified safety controls, pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased capital and operational costs or operational delays that could be significant and have a material adverse effect on our financial position or results of operations and ability to make distributions to our unitholders.
Transaction Risks
We have recorded goodwill and other intangible assets that could become further impaired and result in material non-cash charges to our results of operations in the future.
We accounted for our acquisition of Andeavor Logistics LP (“ANDX” and such acquisition, the “Merger”) as a reorganization of entities under common control in accordance with accounting principles generally accepted in the United States. Under a reorganization of entities under common control, the assets and liabilities of ANDX transferred between entities under common control were recorded by MPLX based on MPC’s historical cost basis resulting from its preliminary purchase price accounting. We recorded ANDX’s assets and liabilities at MPC’s basis as of October 1, 2018, the date that common control was first established. Under MPC’s application of the acquisition method of accounting, a portion of the total purchase price was allocated to ANDX’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of October 1, 2018. The excess of the allocated purchase price over those fair values was recorded as goodwill.
In 2020, we recorded approximately $2.0 billion in impairment expense related to goodwill and intangible assets. As of December 31, 2021, our balance sheet reflected $7.7 billion and $0.8 billion of goodwill and intangible assets, respectively. To the extent the value of goodwill or intangible assets becomes further impaired, we may be required to incur additional material non-cash charges relating to such impairment. Our operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.
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If we are unable to make strategic acquisitions on economically acceptable terms from MPC or third parties, our ability to implement our business strategy may be impaired.
In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions. If we are unable to make accretive strategic acquisitions from MPC or third parties that increase the cash generated from operations per unit, whether due to an inability to identify attractive acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.
Future acquisitions will involve the integration of new assets or businesses and may present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.
Future transactions involving the addition of new assets or businesses will present potential risks, which may include, among others:
•inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
•an inability to successfully integrate, or a delay in the successful integration of, assets or businesses we acquire;
•a decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;
•the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
•the diversion of management’s attention from other business concerns;
•the loss of customers or key employees from the acquired businesses; and
•the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.
Risks Relating to the Business and Operations of MPC
MPC accounts for a substantial portion of our revenues. If MPC is unable to satisfy its obligations to us or significantly reduces the volumes transported through our facilities or stored at our storage assets, our revenues would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.
We derive a substantial portion of our revenues from MPC. Any event that materially and adversely affects MPC’s financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business decisions and risks of MPC, which include the following:
•the timing and extent of changes in commodity prices and demand for MPC’s products, and the availability and costs of crude oil and other refinery feedstocks;
•a material decrease in the refining margins at MPC’s refineries;
•disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on which MPC’s business is dependent;
•any decision by MPC to temporarily or permanently alter, curtail or shut down operations at one or more of its refineries or other facilities and reduce or terminate its obligations under our transportation and storage or refining logistics and fuels distribution agreements;
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•changes to the routing of volumes shipped by MPC on our crude oil and refined product pipelines or the ability of MPC to utilize third-party pipeline connections to access our pipelines;
•MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;
•changes in the cost or availability of third-party pipelines, railways, vessels, terminals and other means of delivering and transporting crude oil, feedstocks, refined products and other hydrocarbon-based products;
•state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;
•imposition of new economic sanctions against Russia or other countries and the effects of potential responsive countermeasures;
•environmental incidents and violations and related remediation costs, fines and other liabilities;
•operational hazards and other incidents at MPC’s refineries and other facilities, such as explosions and fires, that result in temporary or permanent shut downs of those refineries and facilities;
•changes in crude oil and refined product inventory levels and carrying costs; and
•disruptions due to hurricanes, tornadoes or other forces of nature.
MPC is not obligated to use our services with respect to volumes in excess of the minimum volume commitments under its agreements with us. If MPC satisfies only its minimum obligations under, or if we are unable to renew or extend, the transportation, terminal, fuels distribution, marketing and storage services agreements we have with MPC, or if MPC elects to use credits upon the expiration or termination of an agreement, our cash available for distribution will be materially and adversely affected.
In addition, significant stockholders of MPC may attempt to effect changes at MPC or acquire control of the company, which could impact the pursuit of MPC’s business strategies. Campaigns by stockholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term stockholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. As a result, stockholder campaigns at MPC could directly or indirectly adversely affect our results of operations and financial condition and our ability to sustain or increase distributions to our unitholders.
MPC may suspend, reduce or terminate its obligations under its agreements with us in some circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
Certain of our transportation, terminal, fuels distribution, marketing and storage services agreements with MPC include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include a material breach of the applicable agreement by us, MPC being prevented from transporting its full minimum volume commitment because of capacity constraints on our pipelines, certain force majeure events that would prevent us from performing some or all of the required services under the applicable agreement and MPC’s determination to suspend refining operations at one of its refineries. MPC has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. These actions could result in a suspension, reduction or termination of MPC’s obligations under one or more transportation and storage services agreements.
Any such reduction, suspension or termination of MPC’s obligations could have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
MPC’s level of indebtedness, the terms of its borrowings and its credit ratings could adversely affect our ability to grow our business and our ability to make distributions to our unitholders. Our ability to obtain credit in the future may also be adversely affected by MPC’s credit rating.
MPC must devote a portion of its cash flows from operating activities to service its indebtedness, and therefore, cash flows may not be available for use in pursuing its growth strategy. Furthermore, a higher level of indebtedness
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at MPC in the future increases the risk that it may default on its obligations to us under our transportation and storage services agreements. As of December 31, 2021, MPC had consolidated long-term indebtedness of approximately $26 billion, of which $7 billion was a direct obligation of MPC or its subsidiaries other than MPLX or its consolidated subsidiaries. The covenants contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner.
Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially and adversely affected.
Rating agencies have in the past, and may in the future, change MPLX’s credit ratings or credit outlook following developments at MPC. If these ratings are lowered in the future, the interest rate and fees MPC pays on its credit facilities may increase. Credit rating agencies will likely consider MPC’s debt ratings when assigning ours because of MPC’s ownership interest in us, the significant commercial relationships between MPC and us, and our reliance on MPC for a portion of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of us or MPC, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make distributions to our unitholders.
Tax Risks
Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this.
A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations, we believe that we are treated as a partnership rather than as a corporation for such purposes; however, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes. The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.
If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21 percent, and likely would pay state and local income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate dividends, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. Changes in current state or local law may subject us to additional entity-level taxation by individual states and localities. For example, we are currently subject to state and local taxes in Texas and Tennessee and certain localities in Kentucky, Michigan and Ohio. Imposition of any such additional taxes on us may substantially reduce the cash available for distribution to unitholders.
Our Partnership Agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
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If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.
The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
Our unitholders will be required to pay taxes on their share of income even if they do not receive any distributions from us.
Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to their units will, in effect, increase taxable income to the unitholder. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur taxable income in excess of the amount of cash received from the sale.
Tax-exempt entities face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Furthermore, a tax-exempt entity’s gain on sale of common units may be treated, at least in part, as unrelated business taxable income. Tax-exempt entities should consult their tax advisor before investing in our common units.
Non-U.S. unitholders will be subject to United States taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Non-U.S. persons will also potentially have tax filings and payment obligations in additional jurisdictions.
We treat each purchaser of common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
Because we cannot match transferors and transferees of common units and to enable the uniformity of the economic and tax characteristics of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these
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tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.
Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.
In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in a substantial number of states, most of which currently impose a personal income tax and many of which impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states. It is our unitholders’ responsibility to file all U.S. federal, state and local tax returns.
We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.
When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, or our allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.
A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.
A unitholder whose common units are the subject of a securities loan (e.g., a loan to a short seller) may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
A unitholder whose common units are the subject of a securities loan (i) may be considered as having disposed of the loaned common units, (ii) may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and (iii) may recognize gain or loss from such disposition.
Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a securities loan are urged to consult a tax adviser to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. From time to time, the President and members of the U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.
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For example, the Biden Administration’s May 2021 budget proposal included a proposal that would have repealed the application of the qualifying income exception to partnerships with income and gains from activities relating to fossil fuels for taxable years beginning after 2026.
We are unable to predict whether any such changes will ultimately be enacted. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of our general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the allocation date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
Unitholders may be subject to limitations on their ability to deduct interest expense we incur.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) discussed below, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022.
If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have certain limited rights to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or choose to do so) under all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be reduced.
Common Unit Ownership Risks
Our general partner and its affiliates, including MPC, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over MPC’s business decisions and operations, and MPC is under no obligation to adopt a business strategy that favors us.
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MPC owns our general partner and approximately 64 percent of our outstanding common units as of February 15, 2022. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, MPC.
Conflicts of interest may arise between MPC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including MPC, over the interests of our common unitholders, which may occur under our Partnership Agreement without being independently reviewed by the conflicts committee. These conflicts include, among others, the following situations:
•neither our Partnership Agreement nor any other agreement requires MPC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease refinery production, shut down or reconfigure a refinery, or pursue and grow particular markets;
•MPC’s directors and officers have a fiduciary duty to make decisions in the best interests of the stockholders of MPC;
•disputes may arise under agreements pursuant to which MPC and its affiliates are our customers;
•MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
•except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
•our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
•our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the amount of adjusted operating surplus generated in any given period;
•our general partner will determine which costs incurred by it are reimbursable by us and may cause us to pay it or its affiliates for any services rendered to us;
•our general partner may cause us to borrow funds in order to permit the payment of distributions;
•our Partnership Agreement permits us to classify up to $60 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner;
•our Partnership Agreement does not restrict our general partner from entering into additional contractual arrangements with it or its affiliates on our behalf;
•our general partner intends to limit its liability regarding our contractual and other obligations;
•our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 85 percent of the common units;
•our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our transportation and storage services agreements with MPC; and
•our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
Under the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners.
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Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.
Our Partnership Agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
Our Partnership Agreement requires that we distribute all of our available cash to our unitholders. As a result, we may require external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.
Our Partnership Agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties and restricts the remedies available to unitholders for actions taken by our general partner.
Our Partnership Agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing. Our general partner is entitled to consider only the interests and factors that it desires and is relieved of any duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or our limited partners.
Our Partnership Agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement:
•provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;
•provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;
•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
•provides that our general partner will not be in breach of its obligations under our Partnership Agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our Partnership Agreement.
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In connection with a transaction with an affiliate or a conflict of interest, our Partnership Agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our Partnership Agreement, including the provisions discussed above.
Unitholders have very limited voting rights and, even if they are dissatisfied, they have limited ability to remove our general partner without its consent.
Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are wholly owned subsidiaries of MPC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding common units voting together as a single class is required to remove our general partner. As of February 15, 2022, our general partner and its affiliates owned approximately 64 percent of the outstanding common units (excluding common units held by officers and directors of our general partner and MPC). As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Furthermore, unitholders’ voting rights are further restricted by the Partnership Agreement provision providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.
Our Partnership Agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.
If unitholders are not both citizenship-eligible holders and rate-eligible holders, their common units may be subject to redemption.
In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate-eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If unitholders are not persons who meet the requirements to be citizenship-eligible holders and rate-eligible holders, they run the risk of having their units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if unitholders are not persons who meet the requirements to be citizenship eligible holders, they will not be entitled to voting rights.
Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce our cash available for distribution.
Under our Partnership Agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreements or our employee services agreements, our general partner
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determines the amount of these expenses. Under the terms of the omnibus agreements, we will be required to reimburse MPC for the provision of certain general and administrative services to us. Under the terms of our employee services agreements, we have agreed to reimburse MPC or its affiliates for the provision of certain operational and management services to us in support of our facilities. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders.
The control of our general partner may be transferred to a third party without unitholder consent.
There is no restriction in our Partnership Agreement on the ability of MPC to transfer its membership interest in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.
We may issue additional units without unitholder approval, which will dilute limited unitholder interests.
At any time, we may issue an unlimited number of limited partner interests of any type, including limited partner interests that are convertible into our common units, without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our Partnership Agreement nor our bank revolving credit facility prohibits the issuance of additional preferred units, or other equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units, preferred units or other equity securities of equal or senior rank will have the following effects:
•our unitholders’ proportionate ownership interest in us will decrease;
•it may be more difficult to maintain or increase our distributions to unitholders, and the amount of cash available for distribution on each unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding unit may be diminished; and
•the market price of our common units may decline.
MPC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.
As of February 15, 2022, MPC held 647,415,452 common units. Additionally, we have agreed to provide MPC with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.
Affiliates of our general partner, including MPC, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.
MPC and other affiliates of our general partner are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, MPC and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from MPC and other affiliates of our general partner could materially and adversely impact our results of operations and cash available for distribution to unitholders.
Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 85 percent of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of such units.
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A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. A unitholder could be liable for our obligations as if they were a general partner if a court or government agency were to determine that:
•we were conducting business in a state but had not complied with that particular state’s partnership statute; or
•a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.
•
Unitholders may have to repay distributions that were wrongfully distributed to them.
Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our Partnership Agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.
We list our common units on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
The Court of Chancery of the State of Delaware will be, to the extent permitted by law, the sole and exclusive forum for substantially all disputes between us and our limited partners.
Our limited partnership agreement provides that the Court of Chancery of the State of Delaware will be the sole and exclusive forum for any claims, actions or proceedings:
•arising out of or relating in any way to our limited partnership agreement, or the rights or powers of, or restrictions on, our limited partners or the limited partnership;
•brought in a derivative manner on behalf of the limited partnership;
•asserting a claim of breach of a duty owed by any director, officer, or other employee of the limited partnership or the general partner, or owed by the general partner, to the partnership or the limited partners;
•asserting a claim arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act; or
•asserting a claim governed by the internal affairs doctrine.
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The forum selection provision may restrict a limited partner's ability to bring a claim against us or directors, officers or other employee of ours or our general partner in a forum that it finds favorable, which may discourage limited partners from bringing such claims at all. Alternatively, if a court were to find the forum selection provision contained in our limited partnership agreement to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in another forum, which could materially adversely affect our business, financial condition and results of operations. However, the forum selection provision does not apply to any claims, actions or proceedings arising under the Securities Act or the Exchange Act.
Item 1B. Unresolved Staff Comments
None
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Item 2. Properties
LOGISTICS AND STORAGE
Crude Oil and Refined Product Pipelines
The following table sets forth information regarding our crude oil and refined product pipeline systems, which we own or have an interest in as of December 31, 2021.
| Diameter | Length (miles)(1)(2)(3) | Capacity | ||||||||||||||||||
| Total Crude Systems | 2" - 48" | 8,752 | Various | |||||||||||||||||
| Total Refined Products Systems | 4" - 42" | 6,465 | Various | |||||||||||||||||
(1) Includes approximately 16 miles of crude pipeline and approximately 2 miles of refined product pipeline leased from third parties.
(2) Includes approximately 1,916 miles of crude pipeline in which we have a 9 percent ownership interest, 168 miles of crude pipeline in which we have a 35 percent ownership interest, 48 miles of crude pipeline in which we have a 41 percent ownership interest, 57 miles of crude pipeline in which we have a 59 percent ownership interest, 522 miles of crude pipeline in which we have an 11 percent ownership interest, 107 miles of crude pipeline in which we have a 67 percent ownership interest and 975 miles of crude pipeline in which we have a 17 percent ownership interest. Also includes approximately 1,830 miles of refined product pipeline in which we have a 25 percent ownership interest, 87 miles of refined product pipeline in which we have a 65 percent ownership interest, 78 miles of refined product pipeline in which we have a 25 percent ownership interest, 323 miles of refined product pipeline in which we have an 8 percent interest, 498 miles of refined product pipeline in which we have a 38 percent interest and 17 miles of refined product pipeline in which we have a 50 percent interest.
(3) Includes approximately 1,161 miles of inactive crude pipeline and 201 miles of inactive refined product pipeline.
Our crude oil pipeline and related assets are strategically positioned to support diverse and flexible crude oil supply options for MPC’s refineries, which receive imported and domestic crude oil through a variety of sources. Imported and domestic crude oil is transported to supply hubs from a variety of regions, including: Cushing, Oklahoma; Western Canada; Wyoming; North Dakota; the Gulf Coast and Patoka, Illinois. Crude oil pipelines from the Delaware and Midland Basins, as well as from the Bakken region transport crude oil into major regional takeaway pipelines and refining centers. Our major crude oil pipelines are connected to these supply hubs and transport crude oil to refineries owned by MPC and third parties.
Our pipelines are strategically positioned to supply feedstocks to MPC refineries and transport refined products from certain MPC refineries to MPC and MPLX operations, as well as those of third parties. These refined product pipelines are integrated with MPC’s and MPLX’s expansive network of refined product terminals, which support MPC’s integrated midstream business.
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Terminal Assets
The following table sets forth certain information regarding our owned and operated terminals as of December 31, 2021.
Owned and Operated Terminals(1) | Number of Terminals | Tank Shell Capacity (mbbls) | Number of Tanks | |||||||||||||||||
| Refined Product Terminals: | ||||||||||||||||||||
| Alabama | 2 | 443 | 16 | |||||||||||||||||
| Alaska | 3 | 1,572 | 35 | |||||||||||||||||
| California | 8 | 3,483 | 66 | |||||||||||||||||
| Florida | 4 | 3,383 | 63 | |||||||||||||||||
| Georgia | 4 | 982 | 30 | |||||||||||||||||
| Idaho | 3 | 1,000 | 50 | |||||||||||||||||
| Illinois | 4 | 1,124 | 32 | |||||||||||||||||
| Indiana | 6 | 3,217 | 60 | |||||||||||||||||
| Kentucky | 6 | 2,587 | 56 | |||||||||||||||||
| Louisiana | 2 | 5,404 | 52 | |||||||||||||||||
| Michigan | 8 | 2,440 | 73 | |||||||||||||||||
| Minnesota | 1 | 13 | 5 | |||||||||||||||||
| New Mexico | 3 | 481 | 23 | |||||||||||||||||
| North Carolina | 3 | 1,356 | 27 | |||||||||||||||||
| North Dakota | 1 | — | — | |||||||||||||||||
| Ohio | 12 | 3,200 | 100 | |||||||||||||||||
| Pennsylvania | 1 | 390 | 12 | |||||||||||||||||
| South Carolina | 1 | 371 | 8 | |||||||||||||||||
| Tennessee | 4 | 1,149 | 30 | |||||||||||||||||
| Texas | 1 | 73 | 14 | |||||||||||||||||
| Utah | 1 | 21 | 2 | |||||||||||||||||
| Washington | 4 | 920 | 26 | |||||||||||||||||
| West Virginia | 2 | 1,587 | 25 | |||||||||||||||||
| Total Refined Product Terminals | 84 | 35,196 | 805 | |||||||||||||||||
| Asphalt Terminals: | ||||||||||||||||||||
| Arizona | 3 | 554 | 58 | |||||||||||||||||
| California | 3 | 786 | 55 | |||||||||||||||||
| Minnesota | 1 | 529 | 8 | |||||||||||||||||
Nevada(2) | 1 | 283 | 19 | |||||||||||||||||
| New Mexico | 1 | 38 | 9 | |||||||||||||||||
| Texas | 1 | 194 | 19 | |||||||||||||||||
| Total Asphalt Terminals | 10 | 2,384 | 168 | |||||||||||||||||
| Total Terminals | 94 | 37,580 | 973 | |||||||||||||||||
(1) MPLX also operates one leased terminal and has partial ownership interest in one terminal, with a combined tank shell capacity of 1,010 mbbls.
(2) This terminal is accounted for as an equity method investment.
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Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2021. The marine business currently has an associated transportation service agreement with MPC.
| Marine Vessels | Number of Boats and Barges | Capacity (thousand barrels) | ||||||||||||
| Inland tank barges | 297 | 7,832 | ||||||||||||
| Inland towboats | 23 | N/A | ||||||||||||
Our fleet of boats and barges transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks to and from refineries and terminals owned by MPC in the Mid-Continent and Gulf Coast regions. We also have a MRF, which is a full-service marine shipyard, located on the Ohio River, adjacent to MPC’s Catlettsburg, Kentucky refinery. The MRF is responsible for the preventive routine and unplanned maintenance of towing vessels, barges and local terminal facilities.
Refining Logistics Assets
The following table outlines the tankage owned by us, serving MPC’s refineries as of December 31, 2021. We also own and operate rail and truck racks and docks at certain of these refineries. Each of the following assets are currently included in storage services agreements with MPC.
| MPC Refining Logistics Assets | Tank Capacity (mbbls) | |||||||
| Galveston Bay, Texas City, Texas | 18,859 | |||||||
| Garyville, Louisiana | 17,320 | |||||||
| Los Angeles, California | 13,886 | |||||||
| Robinson, Illinois | 7,017 | |||||||
Martinez, California(1) | 5,672 | |||||||
| Anacortes, Washington | 5,448 | |||||||
| Catlettsburg, Kentucky | 5,098 | |||||||
| Detroit, Michigan | 4,984 | |||||||
| El Paso, Texas | 4,920 | |||||||
| Kenai, Alaska | 3,558 | |||||||
| Mandan, North Dakota | 2,787 | |||||||
| Canton, Ohio | 2,698 | |||||||
| Salt Lake City, Utah | 2,159 | |||||||
| St. Paul Park, Minnesota | 865 | |||||||
| Total | 95,271 | |||||||
(1) Associated with MPC refinery expected to convert into a renewable fuels facility.
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Other L&S Assets
The following tables set forth certain information regarding our other midstream assets as of December 31, 2021, each of which currently has an associated transportation services agreement or storage services agreement with MPC.
| Asset Name | Capacity(1) | Associated MPC Refineries | ||||||||||||
LOOP(2) | N/A | Garyville, LA | ||||||||||||
| Barge Docks | 2,010 | mbpd | Multiple | |||||||||||
Tank Farms(3) | 35,144 | mbbls | N/A | |||||||||||
| Caverns | 4,764 | mbbls | N/A | |||||||||||
| Pipeline Name | Diameter (inches) | Length (miles) | Capacity (mbpd) | |||||||||||||||||
| Belfield water system | 3" - 4" | 103 | Various | |||||||||||||||||
| Green River water system | 4" - 8" | 11 | Various | |||||||||||||||||
(1) Capacity for Tank Farms is shown as 100 percent of the available storage capacity. Capacity for the Barge Dock is shown as 100 percent of the throughput capacity. Capacity for caverns is shown as the storage commitment.
(2) We have a 41 percent interest in LOOP, which includes a deep-water oil port and crude oil storage.
(3) We own and operate 32 tank farms and operate one leased tank farm.
GATHERING AND PROCESSING
The following tables set forth certain information relating to our consolidated and operated joint venture gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines as of and for the year ended December 31, 2021. See further discussion about our joint ventures in Item 8. Financial Statements and Supplementary Data - Note 5.
Gas Processing Complexes
| Region | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput(1) (MMcf/d) | Utilization of Design Capacity(1) | |||||||||||||||||
| Marcellus Operations | 6,320 | 5,639 | 91 | % | ||||||||||||||||
| Utica Operations | 1,325 | 482 | 36 | % | ||||||||||||||||
| Southern Appalachia Operations | 495 | 231 | 47 | % | ||||||||||||||||
Southwest Operations(2)(3) | 2,125 | 1,301 | 66 | % | ||||||||||||||||
| Bakken Operations | 185 | 149 | 81 | % | ||||||||||||||||
| Rockies Operations | 1,177 | 429 | 36 | % | ||||||||||||||||
| Total Gas Processing | 11,627 | 8,231 | 72 | % | ||||||||||||||||
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(2) Centrahoma Processing LLC’s processing capacity of 550 MMcf/d and actual throughput of 170 MMcf/d are not included in this table as we own a non-operating 40 percent interest in this joint venture.
(3) The Southwest Operations include throughput for the Javelina complex, which was sold on February 12, 2021. The capacity for this facility is not included in the table above. The processing volumes calculated for the number of days MPLX owned these assets during 2021 were 96 MMcf/d.
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Fractionation & Condensate Stabilization Facilities
| Region | Design Throughput Capacity (mbpd) | NGL Throughput(1) (mbpd) | Utilization of Design Capacity(1) | |||||||||||||||||
Marcellus Operations(2)(3) | 413 | 314 | 76 | % | ||||||||||||||||
Utica Operations(2)(3)(4) | 23 | 13 | 57 | % | ||||||||||||||||
Southern Appalachia Operations(2)(5) | 24 | 12 | 50 | % | ||||||||||||||||
| Bakken Operations | 33 | 23 | 70 | % | ||||||||||||||||
| Rockies Operations | 5 | 4 | 80 | % | ||||||||||||||||
Total C3+ Fractionation and Condensate Stabilization(6) | 498 | 366 | 73 | % | ||||||||||||||||
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(2) Certain complexes have above-ground NGL storage with a usable capacity of 1,346 thousand barrels, large-scale truck and rail loading. We also have access to up to an additional 800 thousand barrels of propane storage capacity that can be utilized by our assets in the Marcellus, Utica and Appalachia regions under an agreement with a third party. Lastly, we have up to 180 thousand barrels of propane storage with a third party that can be utilized by our assets in the Marcellus Shale and Utica Shale.
(3) The capacity, throughput and utilization of design capacity at the Hopedale fractionation complex is presented in the Marcellus Shale totals, however, the Hopedale fractionation complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”). Ohio Fractionation is a joint venture between MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”) and Sherwood Midstream (a joint venture between MarkWest Liberty Midstream and Antero Midstream LLC). MarkWest Liberty Midstream and Sherwood Midstream are entities that operate in the Marcellus region, and MarkWest Utica EMG is an entity that operates in the Utica region. During the year ended December 31, 2021, the Marcellus Operations and Utica Operations utilized an average of 91 percent and 9 percent of the Hopedale fractionation complex, respectively. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 40 mbpd of capacity in the Hopedale 3 and 4 fractionators.
(4) We have access to 100 thousand barrels of condensate storage in this region.
(5) This region includes complexes with both above-ground, pressurized NGL storage facilities, with usable capacity of 48 thousand barrels, and underground storage facilities, with usable capacity of 238 thousand barrels. Product can be received by truck, pipeline or rail and can be transported from the facility by truck, rail or barge.
(6) The total does not include throughput for the Javelina complex, which was sold on February 12, 2021. The fractionated volumes calculated for the number of days MPLX owned these assets during 2021 were 11 mbpd and the throughput for the year was 1 mbpd.
De-ethanization Facilities
| Region | Design Throughput Capacity (mbpd) | NGL Throughput(1) (mbpd) | Utilization of Design Capacity(1) | |||||||||||||||||
| Marcellus Operations | 269 | 191 | 71 | % | ||||||||||||||||
| Utica Operations | 40 | 5 | 13 | % | ||||||||||||||||
| Rockies Operations | 5 | — | — | % | ||||||||||||||||
Total De-ethanization(2) | 314 | 196 | 63 | % | ||||||||||||||||
(1) NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(2) The total does not include throughput for the Javelina complex, which was sold on February 12, 2021. The fractionated volumes calculated for the number of days MPLX owned these assets during 2021 were 6 mbpd and the throughput for the year was 1 mbpd.
Natural Gas Gathering Systems
| Region | Design Throughput Capacity (MMcf/d) | Natural Gas Throughput(1) (MMcf/d) | Utilization of Design Capacity(1) | |||||||||||||||||
| Marcellus Operations | 1,547 | 1,336 | 86 | % | ||||||||||||||||
| Utica Operations | 3,183 | 1,690 | 53 | % | ||||||||||||||||
| Southwest Operations | 2,960 | 1,494 | 54 | % | ||||||||||||||||
| Bakken Operations | 189 | 150 | 79 | % | ||||||||||||||||
Rockies Operations(2) | 1,486 | 461 | 31 | % | ||||||||||||||||
| Total Natural Gas Gathering | 9,365 | 5,131 | 56 | % | ||||||||||||||||
(1) Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
(2) This region does not include our operated joint venture, Rendezvous Gas Services, L.L.C. (“RGS”), which has a gathering capacity of 1,032 MMcf/d; this system supports other systems which are included in the Rockies region and that throughput is presented in the table above. The third party volumes gathered for RGS during the year ended December 31, 2021 were 127 MMcf/d.
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NGL Pipelines
| Region | Diameter | Length (miles) | Design Throughput Capacity (mbpd) | |||||||||||||||||
| Marcellus Operations | 4" - 20" | 442 | Various | |||||||||||||||||
| Utica Operations | 4" - 12" | 119 | Various | |||||||||||||||||
| Southern Appalachia Operations | 6" - 8" | 138 | 35 | |||||||||||||||||
Southwest Operations(1) | 6" | 50 | 39 | |||||||||||||||||
| Bakken Operations | 8" - 12" | 84 | 80 | |||||||||||||||||
| Rockies Operations | 8" | 10 | 15 | |||||||||||||||||
(1) Includes 38 miles of inactive pipeline.
Title to Properties
We believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. In many instances, lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants, as well as potential conflicts with other mineral or surface use owners. We have obtained, where determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, as applicable. We also have obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Some of the property rights we have obtained are revocable at the election of the grantor. In addition, our L&S segment leases vehicles, building spaces, and pipeline equipment under long-term operating leases, most of which include renewal options. Many of our compression, processing, fractionation and other facilities, including certain fractionation plants and certain of our pipelines and other facilities, are on land that we either own in fee or that is held under long-term leases. For any such facilities that are on land that we lease, we could be required to remove our facilities upon the termination or expiration of the leases.
Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or other right to our material land assets. Title to these properties is subject to encumbrances in some cases, such as coal, that may require payment to other holders of title in the property at issue; however, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with their use in the operation of our business. See Item 8. Financial Statements and Supplementary Data – Note 20, for additional information regarding our leases.
MPC indemnifies us for certain title defects and for failures to obtain certain consents and permits necessary to conduct our business with respect to the assets contributed to us by MPC. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with acquisition of real property, liens that can be imposed in some jurisdictions for government-initiated action to clean up environmental contamination, liens for current taxes and other burdens, and easements, restrictions and other encumbrances to which the underlying properties were subject at the time of acquisition. We believe that none of these burdens should materially detract from the value of these properties or from our interest in these properties or should materially interfere with their use in the operation of our business.
Item 3. Legal Proceedings
We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.
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Item 103 of Regulation S-K promulgated by the SEC requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions, unless we reasonably believe that the matter will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than $300,000.
Dakota Access Pipeline
We hold a 9.19 percent indirect interest in a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system or DAPL. In 2020, the U.S. District Court for the District of Columbia (the “D.D.C.”) ordered the U.S. Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The EIS is currently expected to be completed in the second half of 2022.
In May 2021, the D.D.C. denied a renewed request for an injunction to shut down the pipeline while the EIS is being prepared. In June 2021, the D.D.C. issued an order dismissing without prejudice the tribes’ claims against the Dakota Access Pipeline. The litigation could be reopened or new litigation challenging the EIS, once completed, could be filed. The pipeline remains operational.
We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of construction of the Bakken Pipeline system.
If the pipeline were temporarily shut down, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is shutdown. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the permit and/or return the pipeline into operation. If the vacatur of the easement permit results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the 1% redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of December 31, 2021, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $230 million.
Tesoro High Plains Pipeline
In July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the Bureau of Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline that crosses the Fort Berthold Reservation in North Dakota. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. On appeal, the Assistant Secretary - Indian Affairs vacated the BIA’s trespass order and remanded to the Regional Director for the BIA Great Plains Region to issue a new decision based on specified criteria. On December 15, 2020, the Regional Director of the BIA issued a new trespass notice to THPP, finding that THPP was in trespass and assessing trespass damages of approximately $4 million (including interest). The order also required that THPP immediately cease and desist use of the portion of the pipeline that crosses the property at issue. THPP has complied with the Regional Director’s December 15, 2020 notice. In March 2021, THPP received a copy of an order purporting to vacate all orders related to THPP’s alleged trespass issued by the BIA between July 2, 2020 and January 14, 2021. The order directs the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order, if necessary, after all interested parties have had an opportunity to be heard. On April 23, 2021, THPP filed a lawsuit in the District of North Dakota against the United States of America, the U.S. Department of the Interior and the BIA (together, the “U.S. Government Parties”) challenging the March order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the U.S. Government Parties filed their answer to THPP’s suit, asserting counterclaims for trespass and ejectment. The U.S. Government Parties claim THPP is in continued trespass with respect to the pipeline and seek disgorgement of pipeline profits from June 1, 2013 to present, removal of the pipeline and remediation. We intend to vigorously defend ourselves against these counterclaims. We continue to work towards a settlement of this matter with holders of the property rights at issue.
Gathering and Processing
As previously disclosed, we have been negotiating with the EPA with respect to multiple alleged violations of the National Emission Standards for Hazardous Air Pollutants by the Chapita, Coyote Wash, Island, River Bend and Wonsits Valley Compressor Stations in Utah. We are in the process of finalizing a settlement with the EPA pursuant
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to which we expect to pay a cash penalty in excess of $300,000 and enter into a consent decree covering MPLX gas plants and compressor stations located in Utah, North Dakota and Wyoming. We expect to finalize the settlement later in 2022.
Item 4. Mine Safety Disclosure
Not applicable
Part II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common units are listed on the NYSE and traded under the symbol “MPLX.” As of February 15, 2022, there were 243 registered holders of 367,212,222 outstanding common units held by the public. In addition, as of February 15, 2022, MPC and its affiliates owned 647,415,452 of our common units, constituting approximately 64 percent of the outstanding common units. In addition, MPC owns our general partner.
Issuer Purchases of Equity Securities
The following table sets forth a summary of our purchases during the quarter ended December 31, 2021, of equity securities that are registered by MPLX pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.
| Millions of Dollars | ||||||||||||||||||||||||||
| Period | Total Number of Units Purchased | Average Price Paid per Unit(1) | Total Number of Units Purchased as Part of Publicly Announced Plans or Programs | Maximum Dollar Value of Units that May Yet Be Purchased Under the Plans or Programs(2) | ||||||||||||||||||||||
| 10/01/2021-10/31/2021 | 1,728,951 | $ | 30.36 | 1,728,951 | $ | 444 | ||||||||||||||||||||
| 11/01/2021-11/30/2021 | 1,648,746 | 30.70 | 1,648,746 | 394 | ||||||||||||||||||||||
| 12/01/2021-12/31/2021 | 1,965,622 | 28.95 | 1,965,622 | $ | 337 | |||||||||||||||||||||
| Total | 5,343,319 | $ | 29.94 | 5,343,319 | ||||||||||||||||||||||
(1)Amounts in this column reflect the weighted average price paid for units purchased under our unit repurchase authorization. The weighted average price includes commissions paid to brokers on shares repurchased under our unit repurchase authorization.
(2)On November 2, 2020, we announced the board authorization of a unit repurchase program for the repurchase of up to $1 billion of MPLX’s common units held by the public. This unit repurchase authorization has no expiration date.
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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
This section of this Annual Report on Form 10-K does not address certain items regarding the year ended December 31, 2019. Discussion and analysis of 2019 and year-to-year comparisons between 2020 and 2019 not included in this Annual Report on Form 10-K can be found in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2020.
All statements in this section, other than statements of historical fact, are forward-looking statements that are inherently uncertain. See “Disclosures Regarding Forward-Looking Statements” and “Risk Factors” for a discussion of the factors that could cause actual results to differ materially from those projected in these statements. The following information concerning our business, results of operations and financial condition should also be read in conjunction with the information included under Item 1. Business and Item 8. Financial Statements and Supplementary Data.
MPLX OVERVIEW
We are a diversified, large-cap MLP formed by MPC 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 business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”), and Gathering and Processing (“G&P”). Our assets are positioned throughout the United States. The L&S segment is engaged in the gathering, transportation, storage and distribution of crude oil, refined products and other hydrocarbon-based products. The L&S segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The G&P segment provides gathering, processing and transportation of natural gas; and the gathering, transportation, fractionation, storage and marketing of NGLs.
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SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
During 2021, we continued to make progress on our three critical priorities to lower our cost structure, improve our commercial performance and strengthen the competitive position of our assets while also benefiting from strong NGL commodity pricing and the recovery of refined product demand. Significant financial and other highlights for the year ended December 31, 2021 are shown in the chart below. Refer to the Results of Operations and the Liquidity and Capital Resources sections for further details.
(1) Includes impairment of equity method investments within our G&P operating segment of $6 million, $1,264 million and $42 million in 2021, 2020 and 2019, respectively.
(2) Includes impairment expense within our G&P operating segment of $42 million, $2,165 million and $1,197 million in 2021, 2020 and 2019, respectively. Plant, property and equipment were impaired in 2021, goodwill, intangible assets and property, plant and equipment were impaired in 2020 and goodwill was impaired in 2019.
(3) The 2019 amount includes Adjusted EBITDA attributable to Predecessor and DCF adjustments attributable to Predecessor.
Additional highlights for the year ended December 31, 2021 include:
•For the twelve months ended December 31, 2021 we continued to see recovery in the environment in which our business operates. The increased availability of vaccinations and the reductions in travel and business restrictions appeared to drive increased economic activity, including the opening of many businesses and schools as well as more in-person interaction broadly. This drove 2021 improvements in our crude and refined product pipeline throughput levels to levels which exceeded 2019 pre-pandemic levels. While we have seen improved results through 2021, we are unable to predict the potential effects that further resurgences of COVID-19 may have on our financial position and results.
•In line with efforts around portfolio optimization, we closed on the sale of our Javelina plant in Corpus Christi, Texas, during the first quarter of 2021, for $70 million of cash in addition to future consideration contingent on
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the performance of the facility. During the fourth quarter of 2021, we closed on the sale of minor gathering assets in Wyoming for proceeds of $41 million.
•Generated $4.9 billion of net cash provided by operating activities, $4.4 billion of free cash flow, and $1.4 billion of excess cash flow after capital spending and investments and base distributions paid to our common and preferred unitholders.
•With continued focus on strict capital discipline, we reduced our capital spending in 2021 with total growth capital of $509 million versus our initial capital plan of $800 million. The reduced spending was also driven by deferred producer-customer capital spending given the uncertainty related to COVID-19.
•During the year ended December 31, 2021, we returned $630 million to unitholders through the repurchase of 22,907,174 public common units under our $1 billion unit repurchase program that was launched in the fourth quarter of 2020. The repurchase authorization has no expiration date. As of December 31, 2021, $337 million remained available under the program for future repurchases.
•Returned incremental capital to our common unitholders through the payment of a special distribution amount of $0.575 per common unit as well as a 2.5 percent increase in our normal quarterly distribution effective for the third quarter of 2021.
NON-GAAP FINANCIAL INFORMATION
Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA, DCF, free cash flow (“FCF”) and excess/deficit cash flow. The amount of Adjusted EBITDA and DCF generated is considered by the board of directors of our general partner in approving MPLX’s cash distributions.
We define Adjusted EBITDA as net income adjusted for: (i) depreciation and amortization; (ii) provision/(benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) extinguishment of debt; (v) non-cash equity-based compensation; (vi) impairment expense; (vii) net interest and other financial costs; (viii) income/(loss) from equity method investments; (ix) distributions and adjustments related to equity method investments; (x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests and (xiii) other adjustments as deemed necessary. We also use DCF, which we define as Adjusted EBITDA adjusted for: (i) deferred revenue impacts; (ii) sales-type lease payments, net of income; (iii) net interest and other financial costs; (iv) net maintenance capital expenditures; (v) equity method investment capital expenditures paid out; and (vi) other adjustments as deemed necessary. We make a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
We define FCF as net cash provided by operating activities adjusted for: (i) net cash used in investing activities; (ii) contributions from MPC; (iii) contributions from noncontrolling interests and (iv) distributions to noncontrolling interests. We define excess/deficit cash flow as FCF less base distributions to common and preferred unitholders.
We believe that the presentation of Adjusted EBITDA, DCF, FCF and excess/deficit cash flow provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities while the GAAP measure most directly comparable to FCF and excess/deficit cash flow is net cash provided by operating activities. These non-GAAP financial measures should not be considered alternatives to GAAP net income or net cash provided by operating activities as they have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. These non-GAAP financial measures should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because non-GAAP financial measures may be defined differently by other companies in our industry, our definitions may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see the Results of Operations section. For a reconciliation of FCF and excess/deficit cash flow to their most directly comparable measure calculated and presented in accordance with GAAP, see the Liquidity and Capital Resources section.
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Management also utilizes Segment Adjusted EBITDA in evaluating the financial performance of our segments. The disclosure of this measure allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources.
COMPARABILITY OF OUR FINANCIAL RESULTS
The comparability of our financial results has been impacted by acquisitions, dispositions, performance of our equity method investments, and impairments among others (see Item 8. Financial Statements and Supplementary Data – Notes 4, 5 and 14).
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RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2021, 2020 and 2019, including a reconciliation of Adjusted EBITDA and DCF from net income and net cash provided by operating activities, the most directly comparable GAAP financial measures.
| (In millions) | 2021 | 2020 | $ Change | 2019 | $ Change | |||||||||||||||||||||||||||
| Revenues and other income: | ||||||||||||||||||||||||||||||||
| Service revenue | $ | 2,313 | $ | 2,397 | $ | (84) | $ | 2,498 | $ | (101) | ||||||||||||||||||||||
| Service revenue - related parties | 3,628 | 3,580 | 48 | 3,455 | 125 | |||||||||||||||||||||||||||
| Service revenue - product related | 345 | 155 | 190 | 140 | 15 | |||||||||||||||||||||||||||
| Rental income | 376 | 398 | (22) | 388 | 10 | |||||||||||||||||||||||||||
| Rental income - related parties | 743 | 952 | (209) | 1,196 | (244) | |||||||||||||||||||||||||||
| Product sales | 1,590 | 636 | 954 | 806 | (170) | |||||||||||||||||||||||||||
| Product sales - related parties | 145 | 128 | 17 | 142 | (14) | |||||||||||||||||||||||||||
| Sales-type lease revenue | 435 | 152 | 283 | 7 | 145 | |||||||||||||||||||||||||||
Income/(loss) from equity method investments(1) | 321 | (936) | 1,257 | 290 | (1,226) | |||||||||||||||||||||||||||
| Other income | 21 | 5 | 16 | 12 | (7) | |||||||||||||||||||||||||||
| Other income - related parties | 110 | 102 | 8 | 107 | (5) | |||||||||||||||||||||||||||
| Total revenues and other income | 10,027 | 7,569 | 2,458 | 9,041 | (1,472) | |||||||||||||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||||||||||||||
| Cost of revenues (excludes items below) | 1,184 | 1,326 | (142) | 1,489 | (163) | |||||||||||||||||||||||||||
| Purchased product costs | 1,585 | 539 | 1,046 | 686 | (147) | |||||||||||||||||||||||||||
| Rental cost of sales | 136 | 135 | 1 | 141 | (6) | |||||||||||||||||||||||||||
| Rental cost of sales - related parties | 109 | 160 | (51) | 165 | (5) | |||||||||||||||||||||||||||
| Purchases - related parties | 1,219 | 1,116 | 103 | 1,231 | (115) | |||||||||||||||||||||||||||
| Depreciation and amortization | 1,287 | 1,377 | (90) | 1,254 | 123 | |||||||||||||||||||||||||||
| Impairment expense | 42 | 2,165 | (2,123) | 1,197 | 968 | |||||||||||||||||||||||||||
| General and administrative expenses | 353 | 378 | (25) | 388 | (10) | |||||||||||||||||||||||||||
| Restructuring expenses | — | 37 | (37) | — | 37 | |||||||||||||||||||||||||||
| Other taxes | 120 | 125 | (5) | 113 | 12 | |||||||||||||||||||||||||||
| Total costs and expenses | 6,035 | 7,358 | (1,323) | 6,664 | 694 | |||||||||||||||||||||||||||
| Income from operations | 3,992 | 211 | 3,781 | 2,377 | (2,166) | |||||||||||||||||||||||||||
| Related party interest and other financial costs | 8 | 5 | 3 | 11 | (6) | |||||||||||||||||||||||||||
| Interest expense (net of amounts capitalized) | 785 | 829 | (44) | 851 | (22) | |||||||||||||||||||||||||||
| Other financial costs | 86 | 62 | 24 | 53 | 9 | |||||||||||||||||||||||||||
| Income/(loss) before income taxes | 3,113 | (685) | 3,798 | 1,462 | (2,147) | |||||||||||||||||||||||||||
| Provision for income taxes | 1 | 2 | (1) | — | 2 | |||||||||||||||||||||||||||
| Net income/(loss) | 3,112 | (687) | 3,799 | 1,462 | (2,149) | |||||||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 35 | 33 | 2 | 28 | 5 | |||||||||||||||||||||||||||
| Less: Net income attributable to Predecessor | — | — | — | 401 | (401) | |||||||||||||||||||||||||||
| Net income/(loss) attributable to MPLX LP | 3,077 | (720) | 3,797 | 1,033 | (1,753) | |||||||||||||||||||||||||||
Adjusted EBITDA attributable to MPLX LP (excluding Predecessor results)(2) | 5,560 | 5,211 | 349 | 4,334 | 877 | |||||||||||||||||||||||||||
Adjusted EBITDA attributable to MPLX LP (including Predecessor results)(2) | 5,560 | 5,211 | 349 | 5,104 | 107 | |||||||||||||||||||||||||||
DCF attributable to GP and LP unitholders (including Predecessor results)(2) | $ | 4,644 | $ | 4,200 | $ | 444 | $ | 3,978 | $ | 222 | ||||||||||||||||||||||
(1)Includes impairment expense related to various equity method investments of $6 million, $1,264 million and $42 million in 2021, 2020 and 2019, respectively.
(2)Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures.
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| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income/(loss): | ||||||||||||||||||||
| Net income/(loss) | $ | 3,112 | $ | (687) | $ | 1,462 | ||||||||||||||
| Provision for income taxes | 1 | 2 | — | |||||||||||||||||
| Amortization of deferred financing costs | 70 | 61 | 42 | |||||||||||||||||
| Gain on extinguishment of debt | (10) | (19) | — | |||||||||||||||||
| Net interest and other financial costs | 819 | 854 | 873 | |||||||||||||||||
| Income from operations | 3,992 | 211 | 2,377 | |||||||||||||||||
| Depreciation and amortization | 1,287 | 1,377 | 1,254 | |||||||||||||||||
| Non-cash equity-based compensation | 9 | 14 | 22 | |||||||||||||||||
| Impairment expense | 42 | 2,165 | 1,197 | |||||||||||||||||
(Income)/loss from equity method investments(1) | (321) | 936 | (290) | |||||||||||||||||
| Distributions/adjustments related to equity method investments | 537 | 499 | 562 | |||||||||||||||||
Unrealized derivative losses/(gains)(2) | 45 | 3 | (1) | |||||||||||||||||
| Restructuring expenses | — | 37 | — | |||||||||||||||||
| Acquisition costs | — | — | 14 | |||||||||||||||||
| Other | 8 | 6 | 1 | |||||||||||||||||
| Adjusted EBITDA | 5,599 | 5,248 | 5,136 | |||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | (39) | (37) | (32) | |||||||||||||||||
Adjusted EBITDA attributable to Predecessor(3) | — | — | (770) | |||||||||||||||||
| Adjusted EBITDA attributable to MPLX LP | 5,560 | 5,211 | 4,334 | |||||||||||||||||
| Deferred revenue impacts | 88 | 144 | 94 | |||||||||||||||||
Sales-type lease payments, net of income (4) | 71 | — | — | |||||||||||||||||
| Net interest and other financial costs | (819) | (854) | (873) | |||||||||||||||||
| Maintenance capital expenditures | (133) | (161) | (262) | |||||||||||||||||
| Maintenance capital expenditures reimbursements | 45 | 46 | 53 | |||||||||||||||||
| Equity method investment capital expenditures paid out | (7) | (23) | (28) | |||||||||||||||||
| Restructuring expenses | — | (37) | — | |||||||||||||||||
| Other | (20) | 1 | 12 | |||||||||||||||||
Portion of DCF adjustments attributable to Predecessor(3) | — | — | 159 | |||||||||||||||||
| DCF | 4,785 | 4,327 | 3,489 | |||||||||||||||||
Preferred unit distributions(5) | (141) | (127) | (122) | |||||||||||||||||
| DCF attributable to GP and LP unitholders | 4,644 | 4,200 | 3,367 | |||||||||||||||||
Adjusted EBITDA attributable to Predecessor(3) | — | — | 770 | |||||||||||||||||
Portion of DCF adjustments attributable to Predecessor(3) | — | — | (159) | |||||||||||||||||
| DCF attributable to GP and LP unitholders (including Predecessor results) | $ | 4,644 | $ | 4,200 | $ | 3,978 | ||||||||||||||
(1)Includes impairment expense related to various equity method investments of $6 million, $1,264 million and $42 million in 2021, 2020 and 2019, respectively.
(2) MPLX makes a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
(3) The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders prior to the acquisition dates.
(4) Includes impact from refining logistics harmonization project of $54 million.
(5) Includes MPLX distributions declared on the Series A preferred units, Series B preferred units and TexNew Mex units, as well as cash distributions earned by the Series B preferred units (as the Series B preferred units are declared and payable semi-annually), assuming a distribution is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A preferred units, Series B preferred units and TexNew Mex units are not available to common unitholders. The TexNew Mex units were eliminated effective February
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1, 2021. The distributions to Series A preferred unitholders for the twelve months ended December 31, 2021 include the Special Distribution Amount of $0.575 per unit, or a total of $18 million in addition to the base distributions.
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities: | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 4,911 | $ | 4,521 | $ | 4,082 | ||||||||||||||
| Changes in working capital items | (202) | (204) | 108 | |||||||||||||||||
| All other, net | (26) | (3) | (9) | |||||||||||||||||
| Non-cash equity-based compensation | 9 | 14 | 22 | |||||||||||||||||
| Net (loss)/gain on disposal of assets | 13 | (4) | 6 | |||||||||||||||||
| Net interest and other financial costs | 819 | 854 | 873 | |||||||||||||||||
| Gain on extinguishment of debt | (10) | (19) | — | |||||||||||||||||
| Current income taxes | 3 | 3 | 2 | |||||||||||||||||
| Asset retirement expenditures | — | — | 1 | |||||||||||||||||
Unrealized derivative losses/(gains)(1) | 45 | 3 | (1) | |||||||||||||||||
| Restructuring expenses | — | 37 | — | |||||||||||||||||
| Acquisition costs | — | — | 14 | |||||||||||||||||
| Other adjustments to equity method investment distributions | 29 | 40 | 37 | |||||||||||||||||
| Other | 8 | 6 | 1 | |||||||||||||||||
| Adjusted EBITDA | 5,599 | 5,248 | 5,136 | |||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | (39) | (37) | (32) | |||||||||||||||||
Adjusted EBITDA attributable to Predecessor(2) | — | — | (770) | |||||||||||||||||
| Adjusted EBITDA attributable to MPLX LP | 5,560 | 5,211 | 4,334 | |||||||||||||||||
| Deferred revenue impacts | 88 | 144 | 94 | |||||||||||||||||
Sales-type lease payments, net of income(3) | 71 | — | — | |||||||||||||||||
| Net interest and other financial costs | (819) | (854) | (873) | |||||||||||||||||
| Maintenance capital expenditures | (133) | (161) | (262) | |||||||||||||||||
| Maintenance capital expenditures reimbursements | 45 | 46 | 53 | |||||||||||||||||
| Equity method investment capital expenditures paid out | (7) | (23) | (28) | |||||||||||||||||
| Restructuring expenses | — | (37) | — | |||||||||||||||||
| Other | (20) | 1 | 12 | |||||||||||||||||
Portion of DCF adjustments attributable to Predecessor(2) | — | — | 159 | |||||||||||||||||
| DCF | 4,785 | 4,327 | 3,489 | |||||||||||||||||
Preferred unit distributions(4) | (141) | (127) | (122) | |||||||||||||||||
| DCF attributable to GP and LP unitholders | 4,644 | 4,200 | 3,367 | |||||||||||||||||
Adjusted EBITDA attributable to Predecessor(2) | — | — | 770 | |||||||||||||||||
Portion of DCF adjustments attributable to Predecessor(2) | — | — | (159) | |||||||||||||||||
| DCF attributable to GP and LP unitholders (including Predecessor results) | $ | 4,644 | $ | 4,200 | $ | 3,978 | ||||||||||||||
(1) MPLX makes a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
(2) The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders prior to the acquisition dates.
(3) Includes one time impact from refining logistics harmonization project of $54 million.
(4) Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B preferred units (as the Series B preferred units are declared and payable semi-annually) assuming a distribution is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B preferred units are not available to common
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unitholders. The distributions to Series A preferred unitholders for the twelve months ended December 31, 2021 include the Special Distribution Amount of $0.575 per unit, or a total of $18 million in addition to the base distributions.
2021 Compared to 2020
Service revenue decreased $84 million in 2021 compared to 2020. This was primarily due to lower volumes in the Southwest, Marcellus and Rockies, which includes impacts related to severe weather and the Javelina divestiture in the Southwest. These decreases were partially offset by an increase in fees due to a contract modification in the Marcellus resulting in a change in the presentation of lease income from rental income to service revenue.
Service revenue-related parties increased $48 million in 2021 compared to 2020. This was primarily due to increased revenue from pipelines and terminals of $251 million from higher throughput volumes. The increase was partially offset by a decrease of $38 million due to a change in the presentation of lease income between service revenue, rental income and other income based on modifications of lease contracts, a $106 million decrease in marine transportation fees due to equipment rate adjustments resulting from the January 2021 contract renewal, and a $56 million decrease due to the transfer of the Western wholesale distribution business to MPC (the “Wholesale Exchange”) in 2020.
Rental income decreased $22 million in 2021 compared to 2020. This was primarily due to a contract modification in the Marcellus resulting in a change in the presentation of lease income from rental income to service revenue, partially offset by higher fees related to contracts in the Marcellus and Southern Appalachia.
Rental income-related parties decreased $209 million in 2021 compared to 2020. This was primarily due to a decrease of $240 million due to a change in the presentation of lease income between service revenue, rental income and sales-type lease revenue based on modification to lease contracts. The decrease was partially offset by increased terminal storage revenue as well as other miscellaneous increases.
Service revenue-product related, product sales and product sales-related parties increased $1,161 million in 2021 compared to 2020. This was primarily due to higher prices in all of the regions of approximately $1,102 million and other product related sales increases, partially offset by the impact related to the Javelina divestiture, impacts related to severe weather in the Southwest, a decrease in volumes in the Rockies and the Wholesale Exchange.
Sales-type lease revenue increased $283 million in 2021 compared to 2020. This was primarily due to a change in the presentation of lease income between service revenue, rental income and sales-type lease revenue due to modifications to lease contracts.
Income (loss) from equity method investments increased $1,257 million in 2021 compared to 2020. This was primarily due to the $1,264 million impairment charge recorded in 2020 for three of our equity affiliates.
Other income and Other income-related parties increased $24 million in 2021 compared to 2020. This was primarily due to gains recognized on the sale of non-core assets.
Cost of revenues decreased $142 million in 2021 compared to 2020. This was primarily due to the Wholesale Exchange, lower operating expenses as a result of cost reduction initiatives and the Javelina divestiture.
Purchased product costs increased $1,046 million in 2021 compared to 2020. This was primarily due to higher prices of $859 million in the Southwest and Southern Appalachia, other product cost increases and an increase of $42 million due to unrealized derivative losses related to an embedded derivative in a natural gas purchase commitment.
Rental cost of sales and rental cost of sales-related parties decreased $50 million in 2021 compared to 2020. This was primarily due to modifications to lease contracts which resulted in costs now being recorded to purchases - related parties, as noted below, as opposed to rental cost of sales - related parties.
Purchases-related parties increased $103 million in 2021 compared to 2020, primarily due to modifications to lease contracts which resulted in costs now being recorded to purchases - related parties as opposed to rental cost of sales - related parties. There were also increases due to higher prices in the Rockies, employee costs from MPC and project-related spend.
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Depreciation and amortization expense decreased $90 million in 2021 compared to 2020. This was primarily due to the write-off of assets under construction and the impairment of refining logistics, pipeline and terminal assets in 2020, all related to assets located at idled MPC refineries as well as to the derecognition of fixed assets due to the modification of certain lease contracts in the current year. These decreases were partially offset by accelerated depreciation in the current year related to assets located at an indefinitely idled MPC refinery, as well as property, plant and equipment placed in service during 2021.
Impairment expense decreased $2,123 million in 2021 compared to 2020. Due to changes in forecasted production growth resulting from the onset of the COVID-19 pandemic, during 2020 we recorded impairment expense of $1,814 million related to goodwill in the Eastern G&P reporting unit, $177 million and $174 million, related to intangible assets and property, plant and equipment, respectively, in the Southwest region.
General and administrative expenses decreased $25 million in 2021 compared to 2020 primarily due to cost reduction initiatives.
Restructuring expenses decreased $37 million in 2021 compared to 2020, due to cost-cutting measures during 2020.
Interest expense and other financial costs (including related parties) decreased $17 million in 2021 compared to 2020. This was primarily due to lower interest expense due to repayment of senior notes during 2021, partially offset by a decrease in capitalized interest due to lower 2021 project spend and an overall loss on debt extinguishments in 2021 compared to a gain on debt extinguishment in 2020.
SEGMENT REPORTING
We classify our business in the following reportable segments: L&S and G&P. Segment Adjusted EBITDA represents Adjusted EBITDA attributable to the reportable segments. Amounts included in net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) provision/(benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) extinguishment of debt; (v) non-cash equity-based compensation; (vi) impairment expense; (vii) net interest and other financial costs; (viii) income/(loss) from equity method investments; (ix) distributions and adjustments related to equity method investments; (x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests; and (xiii) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
The tables below present information about Segment Adjusted EBITDA for the reported segments for the years ended December 31, 2021, 2020 and 2019.
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L&S Segment
L&S Segment Financial Highlights (in millions)
Revenue and other income(1) | Income from operations(1) | Segment Adjusted EBITDA(1) | ||||||
(1) Includes the results of Predecessor through July 30, 2019.
| (In millions) | 2021 | 2020 | $ Change | 2019 | $ Change | ||||||||||||||||||||||||
| Service revenue | $ | 3,918 | $ | 3,889 | $ | 29 | $ | 3,765 | $ | 124 | |||||||||||||||||||
| Rental income | 772 | 985 | (213) | 1,235 | (250) | ||||||||||||||||||||||||
| Product related revenue | 14 | 51 | (37) | 91 | (40) | ||||||||||||||||||||||||
| Sales-type lease revenue | 435 | 152 | 283 | 7 | 145 | ||||||||||||||||||||||||
| Income from equity method investments | 153 | 154 | (1) | 200 | (46) | ||||||||||||||||||||||||
| Other income | 61 | 54 | 7 | 54 | — | ||||||||||||||||||||||||
| Total segment revenues and other income | 5,353 | 5,285 | 68 | 5,352 | (67) | ||||||||||||||||||||||||
| Cost of revenues | 630 | 782 | (152) | 966 | (184) | ||||||||||||||||||||||||
| Purchases - related parties | 913 | 824 | 89 | 872 | (48) | ||||||||||||||||||||||||
| Depreciation and amortization | 546 | 633 | (87) | 503 | 130 | ||||||||||||||||||||||||
| General and administrative expenses | 180 | 203 | (23) | 198 | 5 | ||||||||||||||||||||||||
| Restructuring expenses | — | 29 | (29) | — | 29 | ||||||||||||||||||||||||
| Other taxes | 72 | 71 | 1 | 61 | 10 | ||||||||||||||||||||||||
| Segment income from operations | 3,012 | 2,743 | 269 | 2,752 | (9) | ||||||||||||||||||||||||
| Depreciation and amortization | 546 | 633 | (87) | 503 | 130 | ||||||||||||||||||||||||
| Income from equity method investments | (153) | (154) | 1 | (200) | 46 | ||||||||||||||||||||||||
| Distributions/adjustments related to equity method investments | 262 | 221 | 41 | 267 | (46) | ||||||||||||||||||||||||
| Restructuring expenses | — | 29 | (29) | — | 29 | ||||||||||||||||||||||||
| Acquisition costs | — | — | — | 14 | (14) | ||||||||||||||||||||||||
| Non-cash equity-based compensation | 6 | 10 | (4) | 14 | (4) | ||||||||||||||||||||||||
| Other | 8 | 6 | 2 | 1 | 5 | ||||||||||||||||||||||||
| Adjusted EBITDA attributable to Predecessor | — | — | — | (603) | 603 | ||||||||||||||||||||||||
Segment Adjusted EBITDA(1) | 3,681 | 3,488 | 193 | 2,748 | 740 | ||||||||||||||||||||||||
Capital expenditures(2) | 316 | 498 | (182) | 1,060 | (562) | ||||||||||||||||||||||||
| Investments in unconsolidated affiliates | $ | 33 | $ | 141 | $ | (108) | $ | 289 | $ | (148) | |||||||||||||||||||
(1)See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income table for the reconciliation to the most directly comparable GAAP measure.
(2)Capital expenditures do not include adjustments for asset retirement expenditures.
2021 Compared to 2020
Service revenue increased $29 million in 2021 compared to 2020. This was primarily due to increased volume from pipelines and terminals, partially offset by a $106 million decrease in marine transportation fees, a $56 million decrease due to the Wholesale Exchange, and a decrease of $38 million due to a change in the presentation of lease income between service revenue, rental income and sales-type lease revenue due to modifications to lease contracts.
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Rental income decreased $213 million in 2021 compared to 2020. This was primarily due to a change in the presentation of lease income between service revenue, rental income and sales-type lease revenue due to modifications to lease contracts. The net decreases due to lease contract modifications were offset by increased terminal storage fees as well as higher refining logistics fees as a result of annual fee escalations.
Product related revenue decreased $37 million in 2021 compared to 2020. This was primarily due to the Wholesale Exchange.
Sales-type lease revenue increased $283 million in 2021 compared to 2020. This was primarily due to a change in the presentation of lease income between service revenue, rental income and sales-type lease revenue due to modifications to lease contracts.
Cost of revenues decreased $152 million in 2021 compared to 2020. This was primarily due to the Wholesale Exchange, lower project-related spend and other operating expenses as a result of cost reduction initiatives. In addition, modifications to lease contracts resulted in costs now being recorded to purchases - related parties, as noted below, as opposed to rental cost of sales - related parties, which is included in the decrease being explained here.
Purchases - related parties increased $89 million in 2021 compared to 2020. This was primarily due to modifications to lease contracts which resulted in costs now being recorded to purchases - related parties as opposed to rental cost of sales - related parties, which is included in cost of revenues as noted above. In addition, higher employee related costs and project-related spend also contributed to the increase.
Depreciation and amortization decreased $87 million in 2021 compared to 2020. This was primarily due to the write-off of assets under construction and the impairment of refining, pipeline and terminal assets in 2020, all related to assets located at idled MPC refineries, as well as to the derecognition of fixed assets due to the modification of certain lease contracts in the current year. These decreases were partially offset by accelerated depreciation in 2021 related to assets located at an indefinitely idled MPC refinery, as well as property, plant and equipment placed in service during 2021.
General and administrative expenses decreased $23 million in 2021 compared to 2020. This was primarily due to decreased employee costs from MPC as a result of cost reduction initiatives.
Restructuring expenses decreased $29 million in 2021 compared to 2020. This was due to cost-cutting measures during 2020 that resulted in restructuring charges.
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G&P Segment
G&P Segment Financial Highlights (in millions)
Revenue and other income(1)(2) | Income/(loss) from operations (1)(3) | Segment Adjusted EBITDA(1) | ||||||
(1) Includes the results of Predecessor through July 30, 2019.
(2) Includes impairment expense related to various equity method investments of $6 million, $1,264 million and $42 million in 2021, 2020 and 2019, respectively.
(3) Includes impairment of property, plant and equipment of $42 million and equity method investments of $6 million for 2021, impairment of goodwill of $1,814 million, long-lived assets including intangibles of $351 million and equity method investments of $1,264 million for 2020 and impairment of goodwill of $1,197 million and equity method investments of $42 million for 2019.
| (In millions) | 2021 | 2020 | $ Change | 2019 | $ Change | ||||||||||||||||||||||||
| Service revenue | $ | 2,023 | $ | 2,088 | $ | (65) | $ | 2,188 | $ | (100) | |||||||||||||||||||
| Rental income | 347 | 365 | (18) | 349 | 16 | ||||||||||||||||||||||||
| Product related revenue | 2,066 | 868 | 1,198 | 997 | (129) | ||||||||||||||||||||||||
Income/(loss) from equity method investments(1) | 168 | (1,090) | 1,258 | 90 | (1,180) | ||||||||||||||||||||||||
| Other income | 70 | 53 | 17 | 65 | (12) | ||||||||||||||||||||||||
| Total segment revenues and other income | 4,674 | 2,284 | 2,390 | 3,689 | (1,405) | ||||||||||||||||||||||||
| Cost of revenues | 799 | 839 | (40) | 829 | 10 | ||||||||||||||||||||||||
| Purchased product costs | 1,585 | 539 | 1,046 | 686 | (147) | ||||||||||||||||||||||||
| Purchases - related parties | 306 | 292 | 14 | 359 | (67) | ||||||||||||||||||||||||
| Depreciation and amortization | 741 | 744 | (3) | 751 | (7) | ||||||||||||||||||||||||
| Impairment expense | 42 | 2,165 | (2,123) | 1,197 | 968 | ||||||||||||||||||||||||
| General and administrative expenses | 173 | 175 | (2) | 190 | (15) | ||||||||||||||||||||||||
| Restructuring expenses | — | 8 | (8) | — | 8 | ||||||||||||||||||||||||
| Other taxes | 48 | 54 | (6) | 52 | 2 | ||||||||||||||||||||||||
| Segment income/(loss) from operations | 980 | (2,532) | 3,512 | (375) | (2,157) | ||||||||||||||||||||||||
| Depreciation and amortization | 741 | 744 | (3) | 751 | (7) | ||||||||||||||||||||||||
| Impairment expense | 42 | 2,165 | (2,123) | 1,197 | 968 | ||||||||||||||||||||||||
(Income)/loss from equity method investments(1) | (168) | 1,090 | (1,258) | (90) | 1,180 | ||||||||||||||||||||||||
| Distributions/adjustments related to equity method investments | 275 | 278 | (3) | 295 | (17) | ||||||||||||||||||||||||
| Restructuring expenses | — | 8 | (8) | — | 8 | ||||||||||||||||||||||||
Unrealized derivative losses/(gains)(2) | 45 | 3 | 42 | (1) | 4 | ||||||||||||||||||||||||
| Non-cash equity-based compensation | 3 | 4 | (1) | 8 | (4) | ||||||||||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | (39) | (37) | (2) | (32) | (5) | ||||||||||||||||||||||||
| Adjusted EBITDA attributable to Predecessor | — | — | — | (167) | 167 | ||||||||||||||||||||||||
Segment Adjusted EBITDA(3) | 1,879 | 1,723 | 156 | 1,586 | 137 | ||||||||||||||||||||||||
Capital expenditures(4) | 224 | 441 | (217) | 1,203 | (762) | ||||||||||||||||||||||||
| Investments in unconsolidated affiliates | $ | 118 | $ | 125 | $ | (7) | $ | 424 | $ | (299) | |||||||||||||||||||
(1)Includes impairment expense related to various equity method investments of $6 million, $1,264 million and $42 million in 2021, 2020 and 2019, respectively.
(2)MPLX makes a distinction between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
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(3)See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income table for the reconciliation to the most directly comparable GAAP measure.
(4)Capital expenditures do not include adjustments for asset retirement expenditures.
2021 Compared to 2020
Service revenue decreased $65 million in 2021 compared to 2020. This was primarily due to lower fees from lower volumes in the Southwest, Marcellus and Rockies of $97 million, which includes impacts related to severe weather and the Javelina divestiture in the Southwest, partially offset by an increase in fees in the Marcellus due to a contract modification that resulted in a change in the presentation of revenue from rental income to service revenue.
Rental income decreased $18 million in 2021 compared to 2020. This was primarily due to a contract modification in the Marcellus resulting in a change in the presentation of revenue from rental income to service revenue, partially offset by higher fees related to contracts in the Marcellus and Southern Appalachia.
Product related revenue increased $1,198 million in 2021 compared to 2020. This was primarily due to higher prices in all of the regions of approximately $1,102 million and other product related sales increases, partially offset by lower volumes due to the Javelina divestiture, impacts related to severe weather in the Southwest and a decline in volumes in the Rockies.
Income (loss) from equity method investments increased $1,258 million in 2021 compared to 2020. This increase was driven by impairments recorded in the first quarter of 2020 of $1,264 million due to changes in forecasted production growth resulting from the onset of the COVID-19 pandemic. Also contributing to the increase was higher volumes associated with our Sherwood Midstream LLC and Ohio Condensate Company joint ventures. These increases were partially offset by lower volumes at our joint ventures in the Utica and Southwest regions along with an asset impairment recognized within our Three Rivers Gathering LLC joint venture in the current period.
Other income increased $17 million in 2021 compared to 2020, this variance was primarily due to a gain recognized on asset sales.
Cost of revenues decreased $40 million in 2021 compared to 2020. This decrease is primarily attributable to lower project-related spend and a decrease in other operating expenses, primarily due to cost reduction initiatives, partially offset by higher prices in the Rockies.
Purchased product costs increased $1,046 million in 2021 compared to 2020. This was primarily due to higher prices of $859 million in the Southwest and Southern Appalachia, an increase of $42 million due to unrealized derivative losses related to an embedded derivative in a natural gas purchase commitment and other product cost increases.
Purchases - related parties increased $14 million in 2021 compared to 2020. This was primarily due to higher prices in the Rockies.
Impairment expense decreased $2,123 million in 2021 compared to 2020. As a result of changes in forecasted production growth resulting from the onset of the COVID-19 pandemic, during 2020 we recorded impairment expense of $1,814 million related to goodwill in the Eastern G&P reporting unit, $177 million and $174 million, related to intangible assets and property, plant and equipment, respectively, in the Southwest region. This decrease was partially offset by an impairment recorded during 2021 related to the divestiture of several non-core assets and the closure of other non-core assets.
Restructuring expenses decreased $8 million in 2021 compared to 2020. This was due to cost-cutting measures during 2020 that resulted in restructuring charges.
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Operating Data
| 2021 | 2020 | 2019 | ||||||||||||||||||
| L&S | ||||||||||||||||||||
| Crude oil transported for (mbpd): | ||||||||||||||||||||
| MPC | 2,810 | 2,465 | 2,671 | |||||||||||||||||
| Third parties | 570 | 533 | 557 | |||||||||||||||||
| Total | 3,380 | 2,998 | 3,228 | |||||||||||||||||
| % MPC | 83% | 82% | 83% | |||||||||||||||||
| Refined products transported for (mbpd): | ||||||||||||||||||||
| MPC | 1,982 | 1,477 | 1,629 | |||||||||||||||||
| Third parties | 91 | 237 | 257 | |||||||||||||||||
| Total | 2,073 | 1,714 | 1,886 | |||||||||||||||||
| % MPC | 96% | 86% | 86% | |||||||||||||||||
Average tariff rates ($ per Bbl)(1): | ||||||||||||||||||||
| Crude oil pipelines | $ | 0.95 | $ | 0.96 | $ | 0.94 | ||||||||||||||
| Refined product pipelines | 0.78 | 0.81 | 0.75 | |||||||||||||||||
| Total pipelines | $ | 0.89 | $ | 0.91 | $ | 0.87 | ||||||||||||||
| Terminal throughput (mbpd) | 2,886 | 2,673 | 3,279 | |||||||||||||||||
Marine Assets (number in operation)(2) | ||||||||||||||||||||
| Barges | 297 | 300 | 286 | |||||||||||||||||
| Towboats | 23 | 23 | 23 | |||||||||||||||||
(1)Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels.
(2)Represents total at end of period.
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| 2021 | 2020 | 2019 | ||||||||||||||||||
| G&P Consolidated Entities | ||||||||||||||||||||
| Gathering Throughput (MMcf/d) | ||||||||||||||||||||
| Marcellus Operations | 1,336 | 1,349 | 1,287 | |||||||||||||||||
| Utica Operations | — | — | — | |||||||||||||||||
| Southwest Operations | 1,346 | 1,430 | 1,625 | |||||||||||||||||
| Bakken Operations | 150 | 137 | 151 | |||||||||||||||||
| Rockies Operations | 439 | 511 | 630 | |||||||||||||||||
| Total gathering throughput | 3,271 | 3,427 | 3,693 | |||||||||||||||||
| Natural Gas Processed (MMcf/d) | ||||||||||||||||||||
| Marcellus Operations | 4,150 | 4,198 | 4,192 | |||||||||||||||||
| Utica Operation | — | — | — | |||||||||||||||||
Southwest Operations(1) | 1,328 | 1,471 | 1,629 | |||||||||||||||||
| Southern Appalachia Operations | 231 | 231 | 244 | |||||||||||||||||
| Bakken Operations | 149 | 136 | 151 | |||||||||||||||||
| Rockies Operations | 429 | 502 | 572 | |||||||||||||||||
| Total natural gas processed | 6,287 | 6,538 | 6,788 | |||||||||||||||||
| C2 + NGLs Fractionated (mbpd) | ||||||||||||||||||||
Marcellus Operations(2) | 484 | 472 | 435 | |||||||||||||||||
| Utica Operations | — | — | — | |||||||||||||||||
Southwest Operations(1) | 2 | 18 | 15 | |||||||||||||||||
Southern Appalachia Operations(3) | 12 | 12 | 12 | |||||||||||||||||
| Bakken Operations | 23 | 25 | 24 | |||||||||||||||||
| Rockies Operations | 4 | 4 | 4 | |||||||||||||||||
Total C2 + NGLs fractionated(4) | 525 | 531 | 490 | |||||||||||||||||
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| 2021 | 2020 | 2019 | ||||||||||||||||||
| G&P Consolidated Entities plus Partnership-Operated Equity Method Investments | ||||||||||||||||||||
| Gathering Throughput (MMcf/d) | ||||||||||||||||||||
| Marcellus Operations | 1,336 | 1,349 | 1,287 | |||||||||||||||||
| Utica Operations | 1,690 | 1,818 | 2,200 | |||||||||||||||||
| Southwest Operations | 1,494 | 1,483 | 1,628 | |||||||||||||||||
| Bakken Operations | 150 | 137 | 151 | |||||||||||||||||
| Rockies Operations | 588 | 688 | 828 | |||||||||||||||||
| Total gathering throughput | 5,258 | 5,475 | 6,094 | |||||||||||||||||
| Natural Gas Processed (MMcf/d) | ||||||||||||||||||||
| Marcellus Operations | 5,639 | 5,629 | 5,248 | |||||||||||||||||
| Utica Operations | 482 | 578 | 810 | |||||||||||||||||
Southwest Operations(1) | 1,471 | 1,537 | 1,636 | |||||||||||||||||
| Southern Appalachia Operations | 231 | 231 | 244 | |||||||||||||||||
| Bakken Operations | 149 | 136 | 151 | |||||||||||||||||
| Rockies Operations | 429 | 502 | 572 | |||||||||||||||||
| Total natural gas processed | 8,401 | 8,613 | 8,661 | |||||||||||||||||
| C2 + NGLs Fractionated (mbpd) | ||||||||||||||||||||
Marcellus Operations(2) | 484 | 472 | 435 | |||||||||||||||||
Utica Operations(2) | 26 | 31 | 44 | |||||||||||||||||
Southwest Operations(1) | 2 | 18 | 15 | |||||||||||||||||
Southern Appalachia Operations(3) | 12 | 12 | 12 | |||||||||||||||||
| Bakken Operations | 23 | 25 | 24 | |||||||||||||||||
| Rockies Operations | 4 | 4 | 4 | |||||||||||||||||
Total C2 + NGLs fractionated(4) | 551 | 562 | 534 | |||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Pricing Information | ||||||||||||||||||||
| Natural Gas NYMEX HH ($/MMBtu) | $ | 3.72 | $ | 2.13 | $ | 2.53 | ||||||||||||||
C2 + NGL Pricing/Gal(5) | $ | 0.87 | $ | 0.43 | $ | 0.52 | ||||||||||||||
(1)The Southwest Operations include the Javelina complex, which was sold on February 12, 2021. The processing and fractionated volumes calculated for the number of days MPLX owned these assets during 2021 were 96 MMcf/d and 17 mbpd, respectively.
(2)Entities within the Marcellus and Utica Operations jointly own the Hopedale fractionation complex. Hopedale throughput is included in the Marcellus and Utica Operations based on each region’s utilization of the complex.
(3)Includes NGLs fractionated for the Marcellus Operations and Utica Operations.
(4)Purity ethane makes up approximately 192 mbpd, 188 mbpd and 179 mbpd of MPLX LP consolidated total fractionated products for the years ended December 31, 2021, 2020 and 2019, respectively. Purity ethane makes up approximately 197 mbpd, 194 mbpd and 189 mbpd of MPLX operated total fractionated products for the years ended December 31, 2021, 2020 and 2019, respectively.
(5)C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash, cash equivalents and restricted cash balances were $13 million and $15 million at December 31, 2021 and December 31, 2020, respectively. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years were as follows:
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| Net cash provided by/(used in): | ||||||||||||||||||||
| Operating activities | $ | 4,911 | $ | 4,521 | $ | 4,082 | ||||||||||||||
| Investing activities | (518) | (1,262) | (3,063) | |||||||||||||||||
| Financing activities | (4,395) | (3,259) | (1,089) | |||||||||||||||||
| Total | $ | (2) | $ | — | $ | (70) | ||||||||||||||
Cash Flows Provided by Operating Activities - Net cash provided by operating activities increased $390 million in 2021 compared to 2020, primarily due to net income adjusted for non-cash items.
Cash Flows Used in Investing Activities - Net cash used in investing activities decreased $744 million in 2021 compared to 2020 primarily due to lower capital spending, which reflects our continued focus on strict capital discipline, and decreased contributions to equity method investments.
Cash Flows Used in and Provided by Financing Activities - Financing activities were a $4,395 million use of cash in 2021 compared to a $3,259 million use of cash in 2020. The primary reasons for the increase in the use of cash was due to the return of capital to unitholders through the unit repurchase program and the special distribution paid during the fourth quarter of 2021.
Free Cash Flow - For the year ended December 31, 2021, we generated excess cash flow after capital investments and base distributions, allowing us to return capital to our unitholders through the repurchase $630 million of public common units during 2021 and a special distribution amount of $603 million during the fourth quarter of 2021. The table below provides a reconciliation of FCF and excess/deficit cash flow from net cash provided by operating activities for the twelve months ended December 31, 2021, 2020 and 2019.
| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
Net cash provided by operating activities(1) | $ | 4,911 | $ | 4,521 | $ | 4,082 | |||||||||||
| Adjustments to reconcile net cash provided by operating activities to free cash flow | |||||||||||||||||
| Net cash used in investing activities | (518) | (1,262) | (3,063) | ||||||||||||||
| Contributions from MPC | 45 | 50 | 74 | ||||||||||||||
| Contributions from noncontrolling interests | — | — | 95 | ||||||||||||||
| Distributions to noncontrolling interests | (39) | (37) | (30) | ||||||||||||||
| Free cash flow | 4,399 | 3,272 | 1,158 | ||||||||||||||
Base distributions paid to common and preferred unitholders(2) | (2,970) | (3,006) | (3,039) | ||||||||||||||
| Excess (deficit) cash flow | $ | 1,429 | $ | 266 | $ | (1,881) | |||||||||||
(1) The years ended December 31, 2021, and December 31, 2020 include cash from working capital of $202 million and $204 million, respectively, while the year ended December 31, 2019 includes a use of cash for working capital of $108 million.
(2) For the year ended December 31, 2021, this amount excludes the Special Distribution Amount for the third quarter of 2021. For the year ended December 31, 2019, this amount includes distributions to common unitholders and Series B unitholders attributable to the Predecessor.
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Debt and Liquidity Overview
Credit Agreement
MPLX has a revolving credit facility (the “MPLX Credit Agreement”) with a borrowing capacity of $3.5 billion that matures in July 2024. Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin. We are charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on MPLX’s long-term debt.
The MPLX Credit Agreement includes letter of credit issuing capacity of up to $300 million and swingline capacity of up to $150 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1.0 billion, subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended for up to two additional one-year periods subject to, among other conditions, the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date. During 2021, we borrowed $4,175 million under the MPLX Credit Agreement, at an average interest rate of 1.343 percent, and repaid $4,050 million of these borrowings. At December 31, 2021, MPLX had $300 million outstanding borrowings under the facility and less than $1.0 million in letters of credit outstanding, resulting in total availability of approximately $3,200 million, or approximately 91 percent of the borrowing capacity.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict us and/or certain of our subsidiaries from incurring debt, creating liens on our assets and entering into transactions with affiliates. As of December 31, 2021, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.7 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.
Senior Notes
On January 15, 2021, MPLX redeemed all of the $750 million outstanding aggregate principal amount of 5.250 percent senior notes due January 15, 2025, including approximately $42 million aggregate principal amount of senior notes issued by ANDX, at a price equal to 102.625 percent of the principal amount. The payment of $20 million related to the note premium, offset by the immediate expense recognition of $12 million of unamortized debt premium and issuance costs, resulted in a loss on extinguishment of debt of $8 million that is included on the Consolidated Statements of Income as “Other financial costs.”
On September 3, 2021, MPLX redeemed, at par value, all of the $1.0 billion aggregate principal amount of floating rate senior notes due September 2022, which resulted in the immediate expense recognition of $2 million of unamortized debt issuance costs. These costs are included on the Consolidated Statements of Income as “Other financial costs.” This redemption was funded primarily by borrowings under the MPC Loan Agreement.
As of December 31, 2021, we had $18.6 billion in aggregate principal amount of senior notes outstanding. The decrease compared to year-end 2020 resulted from the redemption of all of the $750 million outstanding aggregate principal amount of 5.250 percent senior notes due January 15, 2025 and all of the $1.0 billion aggregate principal amount of floating rate senior notes due September 2022, as discussed above.
MPC Loan Agreement
MPLX is party to a loan agreement with MPC (the “MPC Loan Agreement”). Under the terms of the MPC Loan Agreement, MPC extends loans to MPLX on a revolving basis as requested by MPLX and as agreed to by MPC. The borrowing capacity of the MPC Loan Agreement is $1.5 billion aggregate principal amount of all loans outstanding at any one time. The MPC Loan Agreement is scheduled to expire, and borrowings under the MPC
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Loan Agreement are scheduled to mature and become due and payable on July 31, 2024, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to the maturity date. Borrowings under the MPC Loan Agreement bear interest at the one-month LIBOR plus 1.25 percent or such lower rate as would be applicable to such loans under the MPLX Credit Agreement. Activity on the MPC Loan Agreement for 2021 was as follows:
| (In millions, except %) | December 31, 2021 | ||||
| Borrowings | $ | 8,493 | |||
| Average interest rate of borrowings | 1.341 | % | |||
| Repayments | $ | 7,043 | |||
| Outstanding balance at end of period | $ | 1,450 | |||
For further discussion, see Item 8. Financial Statements and Supplementary Data – Note 6 and Note 17.
Our intention is to maintain an investment grade credit profile. As of February 1, 2022, the credit ratings on our senior unsecured debt were at or above investment grade level as follows:
| Rating Agency | Rating | |||||||
| Moody’s | Baa2 (stable outlook) | |||||||
| Fitch | BBB (stable outlook) | |||||||
| Standard & Poor’s | BBB (stable outlook) | |||||||
The ratings shown above reflect the respective views of the rating agencies. Although it is our intention to maintain a credit profile that supports an investment grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.
The agreements governing our debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings could, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement, which may limit our flexibility to obtain future financing.
Our liquidity totaled $3.26 billion at December 31, 2021, consisting of:
| December 31, 2021 | |||||||||||||||||
| (In millions) | Total Capacity | Outstanding Borrowings | Available Capacity | ||||||||||||||
| MPLX Credit Agreement | $ | 3,500 | $ | (300) | $ | 3,200 | |||||||||||
| MPC Loan Agreement | 1,500 | (1,450) | 50 | ||||||||||||||
| Total | $ | 5,000 | $ | (1,750) | 3,250 | ||||||||||||
| Cash and cash equivalents | 13 | ||||||||||||||||
| Total liquidity | $ | 3,263 | |||||||||||||||
We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit facilities and access to capital markets. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations and quarterly cash distributions. Our material future obligations include interest on debt, payments of debt principal, purchase obligations including contracts to acquire PP&E and our operating leases and service agreements. We may also, from time to time repurchase our senior notes and preferred units in the open market, in tender offers, in privately-negotiated transactions or otherwise in such volumes, at such prices and upon such other terms as we deem appropriate and execute unit repurchases under our unit repurchase program
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MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us. From time to time, we may also consider utilizing other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.
Equity and Preferred Units Overview
The following table summarizes the changes in the number of units outstanding through December 31, 2021:
| (In units) | Total Common Units | ||||
| Balance at December 31, 2019 | 1,058,355,471 | ||||
| Unit-based compensation awards | 478,438 | ||||
| Units redeemed in unit repurchase program | (1,473,843) | ||||
| Wholesale Exchange | (18,582,088) | ||||
| Balance at December 31, 2020 | 1,038,777,978 | ||||
| Unit-based compensation awards | 214,466 | ||||
| Units redeemed in unit repurchase program | (22,907,174) | ||||
| Conversion of Series A preferred units | 93,108 | ||||
| Balance at December 31, 2021 | 1,016,178,378 | ||||
For more details on equity activity, see Item 8. Financial Statements and Supplementary Data – Notes 7 and 9.
Preferred Units
Series A Preferred Units - On May 13, 2016, MPLX completed the private placement of approximately 30.8 million Series A preferred units for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the sale of the preferred units were used for capital expenditures, repayment of debt and general business purposes.
The Series A preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Series A preferred units received cumulative quarterly distributions equal to $0.528125 per unit for each quarter prior to the second quarter of 2018. Beginning with the second quarter of 2018, 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. Distributions paid to Series A preferred unitholders during the years ended December 31, 2021, 2020 and 2019 were $100 million, $81 million and $81 million, respectively. The distribution for the year ended December 31, 2021 includes a Special Distribution Amount of $18 million, or $0.5750 per unit.
In December 2021, certain holders exercised their right to convert a total of 0.1 million Series A preferred units into common units. Approximately 29.5 million Series A preferred units remain outstanding as of December 31, 2021.
Series B Preferred Units - Prior to MPLX’s acquisition of Andeavor Logistics LP (“ANDX” and such acquisition, the “Merger”), ANDX issued 600,000 units of 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests of ANDX at a price to the public of $1,000 per unit. Upon completion of the Merger, the ANDX preferred units converted to preferred units of MPLX representing substantially equivalent limited partnership interests in MPLX. The Series B preferred units are pari passu with the Series A preferred units with respect to distribution rights and rights upon liquidation.
MPLX has the right to redeem some or all of the Series B preferred units, at any time, on or after February 15, 2023. MPLX will pay unitholders the Series B preferred unit redemption price of $1,000 per unit plus any accumulated and unpaid distributions up to the redemption date.
Distributions on the Series B preferred units are payable semi-annually through February 15, 2023, and quarterly thereafter. Distributions paid to Series B preferred unitholders during the years ended December 31, 2021, 2020 and 2019 were $41 million, $41 million and $21 million, respectively.
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Unit Repurchase Program
On November 2, 2020, MPLX announced the board authorization of a unit repurchase program for the repurchase of up to $1 billion of MPLX’s outstanding common units held by the public. MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated unit repurchases or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of repurchases depends upon several factors, including market and business conditions, and repurchases may be suspended, discontinued, or restarted at any time. The repurchase authorization has no expiration date. The following table summarizes activity executed on the unit repurchase program during the years ended 2021 and 2020:
| 2021 | 2020 | ||||||||||
| Units repurchased | 22,907,174 | 1,473,843 | |||||||||
| Value of units repurchased, in millions (including commission costs) | $ | 630 | $ | 33 | |||||||
| Average cost per unit | $ | 27.52 | $ | 22.29 | |||||||
At December 31, 2021, $337 million remained outstanding under the program for future repurchases.
Distributions
We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $267 million per quarter, or $1,067 million per year, based on the number of common units outstanding. On January 25, 2022, we announced that the board of directors of our general partner had declared a distribution of $0.7050 per common unit, which was paid on February 14, 2022 to common unitholders of record on February 4, 2022. This represents a 2.5 percent increase over the fourth quarter 2020 distribution. Although our Partnership Agreement requires that we distribute all of our available cash each quarter, we do not otherwise have a legal obligation to distribute any particular amount per common unit.
The allocation of total quarterly cash distributions to limited and preferred partners is as follows for the years ended December 31, 2021, 2020 and 2019. Our distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned. See additional discussion in Item 8. Financial Statements and Supplementary Data - Note 8.
| (In millions, except per unit data) | 2021 | 2020 | 2019(1) | ||||||||||||||
| Distribution declared: | |||||||||||||||||
| Limited partner common units - public | $ | 1,257 | $ | 1,079 | $ | 988 | |||||||||||
| Limited partner common units - MPC | 2,175 | 1,793 | 1,647 | ||||||||||||||
Total distributions declared to limited partner common units(2) | 3,432 | 2,872 | 2,635 | ||||||||||||||
Series A preferred units(2) | 100 | 81 | 81 | ||||||||||||||
| Series B preferred units | 41 | 41 | 42 | ||||||||||||||
| Total distribution declared | $ | 3,573 | $ | 2,994 | $ | 2,758 | |||||||||||
| Cash distributions declared per limited partner common unit: | |||||||||||||||||
| Quarter ended March 31, | $ | 0.6875 | $ | 0.6875 | $ | 0.6575 | |||||||||||
| Quarter ended June 30, | 0.6875 | 0.6875 | 0.6675 | ||||||||||||||
Quarter ended September 30,(2) | 1.2800 | 0.6875 | 0.6775 | ||||||||||||||
| Quarter ended December 31, | 0.7050 | 0.6875 | 0.6875 | ||||||||||||||
| Year ended December 31, | $ | 3.3600 | $ | 2.7500 | $ | 2.6900 | |||||||||||
(1) The distribution on common units for the year ended December 31, 2019 includes the impact of the issuance of approximately 102 million units issued to public unitholders and approximately 161 million units issued to MPC in connection with the Merger. Due to the timing of the closing, distributions presented in the table above include second quarter 2019 distributions on MPLX common units issued to former ANDX unitholders in connection with the Merger. MPC waived $12.5 million in quarterly distributions under the terms of ANDX's historical partnership agreement, which was instituted in 2017 and was to remain in effect through 2019, the original term of the waiver agreement. As such, the distributions on common units exclude $12.5 million of waived distributions for the three months ended December 31, 2019 and $37.5 million of waived distributions for the year ended December 31, 2019. Also included in the table above is $21 million of distributions on the Series B preferred units subsequent to the Merger as well as $21 million of distributions on the Series B units prior to the Merger and declared and paid by MPLX during the third quarter of 2019.
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(2) Includes the Special Distribution Amount of $0.5750 per unit and base distribution amount of $0.7050 per unit for the third quarter ended September 30, 2021.
Capital Expenditures
Our operations are capital intensive, requiring investments to expand, upgrade, enhance or maintain existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and growth capital expenditures. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, growth capital expenditures are those incurred for acquisitions or capital improvements that we expect will increase our operating capacity for volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of growth capital expenditures include costs to develop or acquire additional pipeline, terminal, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for MPLX.
Our capital expenditures for the past three years are shown in the table below:
| (In millions) | 2021 | 2020 | 2019(1) | |||||||||||||||||
| Capital expenditures: | ||||||||||||||||||||
| Growth capital expenditures | $ | 407 | $ | 778 | $ | 2,000 | ||||||||||||||
| Growth capital reimbursements | — | (4) | (21) | |||||||||||||||||
| Investments in unconsolidated affiliates | 151 | 266 | 713 | |||||||||||||||||
| Return of capital | (36) | (123) | (18) | |||||||||||||||||
| Contributions from noncontrolling interests | — | — | (95) | |||||||||||||||||
| Capitalized interest | (13) | (39) | (50) | |||||||||||||||||
| Total growth capital expenditures | 509 | 878 | 2,529 | |||||||||||||||||
| Maintenance capital expenditures | 133 | 161 | 262 | |||||||||||||||||
| Maintenance capital reimbursements | (45) | (46) | (53) | |||||||||||||||||
| Capitalized interest | (1) | — | (1) | |||||||||||||||||
| Total maintenance capital expenditures | 87 | 115 | 208 | |||||||||||||||||
| Total growth and maintenance capital expenditures | 596 | 993 | 2,737 | |||||||||||||||||
Investments in unconsolidated affiliates(2) | (151) | (266) | (713) | |||||||||||||||||
Return of capital(2) | 36 | 123 | 18 | |||||||||||||||||
Contributions from noncontrolling interests(3) | — | — | 95 | |||||||||||||||||
Growth and maintenance capital reimbursements(4) | 45 | 50 | 74 | |||||||||||||||||
| Decrease/(increase) in capital accruals | (11) | 244 | 146 | |||||||||||||||||
| Capitalized interest | 14 | 39 | 51 | |||||||||||||||||
Additions to property, plant and equipment, net(2) | $ | 529 | $ | 1,183 | $ | 2,408 | ||||||||||||||
(1) Includes capital expenditures of the Predecessor.
(2) Investments in unconsolidated affiliates, return of capital and additions to property, plant and equipment, net are shown as separate lines within investing activities in the Consolidated Statements of Cash Flows.
(3) Contributions from noncontrolling interests are shown as separate line within financing activities in the Consolidated Statements of Cash Flows.
(4) Growth and maintenance capital reimbursements are included in the Contributions from MPC line within financing activities in the Consolidated Statements of Cash Flows.
For 2022, we announced a capital outlook of $900 million which includes growth capital of $700 million, maintenance capital of $140 million and a $60 million investment in unconsolidated affiliates for the repayment of our 9.19 percent indirect share of the Bakken Pipeline joint venture’s debt due in 2022.
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Our growth capital plans are focused on investments in high-return projects to expand and debottleneck our existing assets. The L&S growth capital is directed towards logistics projects in support of MPC’s Martinez Renewable Fuels project, projects in the Permian and Bakken basins and investments in the Permian basin supporting the BANGL and Whistler pipelines. These long-haul NGL and natural gas logistics systems transport product to the U.S. Gulf Coast.
The G&P segment growth capital is directed towards the addition of approximately 200 MMcf/d of processing capacity in the Delaware basin in the Permian to meet increasing producer customer demand and 68 mbpd of de-ethanization capacity in the Marcellus to meet increased in-basin demand, both of which are expected to be completed in the second half of 2022, as well as gathering projects in the basins in which we operate. We continuously evaluate our capital plan and make changes as conditions warrant.
Cash Commitments
The Company’s material cash requirements include the following contractual obligations and other cash commitments as of December 31, 2021.
Our contractual obligations primarily consist of outstanding borrowings on debt, commitment and administrative fees and interest. Additional information for third-party debt is included in Item 8. Financial Statements and Supplementary Data – Note 17. See Item 8. Financial Statements and Supplementary Data – Note 6 for additional information for related party loans. Our cash commitment at December 31, 2021 was $30,847 million.
Our contractual commitment for co-location services agreements was $2,830 million at December 31, 2021. These agreements obligate us to pay MPC for operational and other services provided to the subsidiaries of MPLX Refining Logistics LLC.
Finance and operating leases relate primarily to facilities and equipment under lease, including ground leases, building space, office and field equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note 20 for further discussion about our lease obligations. Our cash commitment at December 31, 2021 was $975 million.
Transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the remaining terms of the agreements, have terms that range from one to 10 years. We expect to pass any minimum payment commitments through to producer customers. Minimum fees due under transportation agreements do not include potential fee increases as required by FERC. See Item 8. Financial Statements and Supplementary Data – Note 21 for further discussion. Our cash commitment at December 31, 2021 was $963 million.
We have commitments under contracts to acquire property, plant and equipment, for which additional information is included in Item 8. Financial Statements and Supplementary Data – Note 21. Our cash commitment at December 31, 2021 was $116 million. These commitments were primarily related to G&P plant expansions.
Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data – Note 16 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2021 for calculating this obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the related keep-whole processing agreement after 2027. Our cash commitment, not including this renewal option, at December 31, 2021 was $66 million.
Our other cash commitments consist of expense projects, right of way and easement obligations and ARO commitments. Our cash commitment at December 31, 2021 was $219 million.
In addition, we have omnibus agreements and employee agreements with MPC. One of the omnibus agreements with MPC addresses 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 general and administrative services to us.
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We also pay MPC additional amounts based on the costs actually incurred by MPC in providing other services, except for the portion of the amount attributable to engineering services, which is based on the amounts actually incurred by MPC and its affiliates plus six percent of such costs. In addition, we are obligated to reimburse MPC for most out-of-pocket costs and expenses incurred by MPC on our behalf.
MPLX has various employee agreements with MPC under which MPLX reimburses MPC for employee benefit expenses, along with the provision of operational and management services in support of both our L&S and G&P segments’ operations.
We incurred $1,614 million of costs under various agreements, including the omnibus and employee agreements for 2021.
Effects of Inflation
Inflation did not have a material impact on our results of operations for the years ended December 31, 2021, 2020 or 2019. However, inflation is a growing concern in the United States economy and may increase the cost to acquire, build or replace property, plant and equipment. It may also significantly increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and expect to continue to pass along a portion of increased costs to our customers in the form of higher fees.
TRANSACTIONS WITH RELATED PARTIES
As of December 31, 2021, MPC owned our general partner and an approximate 64 percent limited partner interest in us. We perform a variety of services for MPC related to the transportation of crude and refined petroleum products via pipeline, truck or marine as well as terminal services, storage services and fuels distribution and marketing services, among others. The services that we provide may be based on regulated tariff rates or on contracted rates. In addition, MPC performs certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services. For further discussion of agreements and activity with MPC and related parties see Item 1. Business and Item 8. Financial Statements and Supplementary Data – Note 6.
Excluding losses for impairment of equity method investments, MPC accounted for 50 percent, 55 percent and 53 percent of our total revenues and other income for 2021, 2020 and 2019, respectively. Of our total costs and expenses, excluding impairment expense, MPC accounted for 26 percent, 30 percent and 30 percent for 2021, 2020 and 2019, respectively.
ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS
We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to remediate environmental damage from any discharge of hazardous, petroleum or chemical substances from our facilities or require us to install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints.
Future expenditures may be required to comply with the CAA and other federal, state and local requirements for our various facilities. The impact of these legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity. MPC will indemnify us for certain of these costs.
If these expenditures, as with all costs, are not ultimately reflected in the fees and tariff rates we receive for our services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary
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depending on a number of factors, including, but not limited to, the age and location of its operating facilities. Our environmental expenditures for each of the past three years were:
| (In millions, except %) | 2021 | 2020 | 2019 | |||||||||||||||||
| Capital | $ | 15 | $ | 26 | $ | 39 | ||||||||||||||
| Percent of total capital expenditures | 3 | % | 3 | % | 2 | % | ||||||||||||||
| Compliance: | ||||||||||||||||||||
| Operating and maintenance | $ | 28 | $ | 24 | $ | 40 | ||||||||||||||
Remediation(1) | 17 | 4 | 10 | |||||||||||||||||
| Total | $ | 45 | $ | 28 | $ | 50 | ||||||||||||||
(1)These amounts include spending charged against remediation reserves, and exclude non-cash accruals for environmental remediation.
We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.
New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.
Our environmental capital expenditures are expected to approximate $14 million in 2022. Actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.
CRITICAL ACCOUNTING ESTIMATES
The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (i) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and (ii) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.
The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See Item 8. Financial Statements and Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.
Fair Value Estimates
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
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The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:
•Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
•Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.
•Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. We use an income or market approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data - Note 15 for disclosures regarding our fair value measurements.
Significant uses of fair value measurements include:
•assessment of impairment of long-lived assets, intangible assets, goodwill and equity method investments;
•assessment of values for assets in implicit leases;
•recorded values for assets acquired and liabilities assumed in connection with acquisitions; and
•recorded values of derivative instruments.
Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Method Investments
Fair value calculated for the purpose of testing our long-lived assets, intangible assets, goodwill and equity method investments for impairment is estimated using the expected present value of future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:
•Future Operating Performance. Our estimates of future operating performance are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions as well as commodity prices. Such estimates are consistent with those used in our planning and capital investment reviews.
•Future volumes. Our estimates of future throughput of crude oil, natural gas, NGL and refined product volumes are based on internal forecasts and depend, in part, on assumptions about our customers’ drilling activity which is inherently subjective and contingent upon a number of variable factors (including future or expected pricing considerations), many of which are difficult to forecast. Management considers these volume forecasts and other factors when developing our forecasted cash flows.
•Discount rate commensurate with the risks involved. We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.
•Future capital requirements. These are based on authorized spending and internal forecasts.
Assumptions about the effects of the COVID-19 pandemic and the macroeconomic environment are inherently subjective and contingent upon the duration of the pandemic and its impact on the macroeconomic environment, which is difficult to forecast. We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
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The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for commodities, a poor outlook for profitability, a significant reduction in pipeline throughput volumes, a significant reduction in natural gas or NGL volumes processed, other changes to contracts or changes in the regulatory environment in which the asset or equity method investment is located.
Long-lived Asset Impairment Assessments
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which is at least at the segment level and in some cases for similar assets in the same geographic region where cash flows can be separately identified. If the sum of the undiscounted cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than the calculated fair value.
Goodwill Impairment Assessments
Unlike long-lived assets, goodwill must be tested for impairment at least annually, and between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level. We have five reporting units, three of which have goodwill allocated to them. A goodwill impairment loss is measured as the amount by which a reporting unit’s carrying value exceeds its fair value, without exceeding the recorded amount of goodwill.
At December 31, 2021, MPLX had three reporting units with goodwill totaling approximately $7.7 billion, which includes goodwill associated with our Crude Gathering reporting unit of $1.1 billion. For the annual impairment assessment as of November 30, 2021, management performed only a qualitative assessment for one reporting unit as we determined it was more likely than not that the fair value of the reporting unit exceeded the carrying value. A quantitative assessment was last performed on this reporting unit at March 31, 2020 which indicated fair value exceeded carrying value by approximately 270 percent. A quantitative assessment was performed for the remaining two reporting units, which resulted in the fair value of the reporting units exceeding their carrying value by 23 percent and 51 percent. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method included management’s best estimates of the discount rate of 7.2 percent as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact future volumes and capital requirements. An increase of one percentage to the discount rate used to estimate the fair value of the reporting units would not have resulted in a goodwill impairment charge as of November 30, 2021.
Significant assumptions used to estimate the reporting units’ fair value included estimates of future cash flows and market information for comparable assets. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the impairment tests will prove to be an accurate prediction of the future. See Item 8. Financial Statements and Supplementary Data - Note 14 for additional information relating to our reporting units and goodwill.
Equity Method Investment Impairment Assessments
Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At December 31, 2021, we had $3,981 million of equity method investments recorded on the Consolidated Balance Sheets.
An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous assumptions (e.g., pricing, volumes and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the above listed adjustments may be offset by favorable adjustments in other assumptions.
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See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on our equity method investments and Note 14 for additional information on our goodwill and intangibles.
Leases
In accounting for leases, MPLX may be required to analyze new or existing leases for lease classification. One of the key inputs into the lease classification analysis is the fair value of the leased assets. Significant assumptions used to estimate the leased assets’ fair value included market information for comparable assets and cost estimates to replace the service capacity of an asset.
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE, we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.
Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.
Changes in the design or nature of the activities of a VIE, or our involvement with a VIE, may require us to reconsider our conclusions on the entity’s status as a VIE and/or our status as the primary beneficiary. Such reconsideration requires significant judgment and understanding of the organization. This could result in the deconsolidation or consolidation of the affected subsidiary, which would have a significant impact on our financial statements.
VIEs are discussed in Item 8. Financial Statements and Supplementary Data - Note 5.
Contingent Liabilities
We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology.
We generally record losses related to these types of contingencies as cost of revenues or selling, general and administrative expenses on the Consolidated Statements of Income, except for tax deficiencies unrelated to income taxes, which are recorded as other taxes.
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions
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and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters and Compliance Costs and Item 8. Financial Statements and Supplementary Data - Note 21.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to market risks related to the volatility of commodity prices. We employ various strategies, including the potential use of commodity derivative instruments, to economically hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates. As of December 31, 2021, we did not have any open financial or commodity derivative instruments to hedge the economic risks related to interest rate fluctuations or the volatility of commodity prices, respectively; however, we continually monitor the market and our exposure and may enter into these arrangements in the future.
Commodity Price Risk
We may at times use a variety of commodity derivative instruments, including futures and options, as part of an overall program to economically hedge commodity price risk. A portion of our profitability is directly affected by prevailing commodity prices primarily as a result of purchasing and selling NGLs and natural gas at index-related prices. To the extent that commodity prices influence the level of drilling by our producer customers, such prices also indirectly affect profitability. We may enter into derivative contracts, which are primarily swaps traded on the Over-the-Counter market as well as fixed price forward contracts. Our risk management policy does not allow us to enter into speculative positions with our derivative contracts. Execution of our hedge strategy and the continuous monitoring of commodity markets and our open derivative positions are carried out by our hedge committee, comprised of members of senior management.
To mitigate our cash flow exposure to fluctuations in the price of NGLs, we may use NGL derivative swap contracts. A small portion of our NGL price exposure may be managed by using crude oil contracts. To mitigate our cash flow exposure to fluctuations in the price of natural gas, we may use natural gas derivative swap contracts, taking into account the partial offset of our long and short natural gas positions resulting from normal operating activities.
We would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver products or if processing facilities are operated in different recovery modes. In the event that we have derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.
Management conducts a standard credit review on counterparties to derivative contracts, and we have provided the counterparties with a guaranty as credit support for our obligations. We use standardized agreements that allow for offset of certain positive and negative exposures in the event of default or other terminating events, including bankruptcy.
Outstanding Derivative Contracts
We have a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer customer in the Southern Appalachian region expiring in December 2027. The customer has the unilateral option to extend the agreement for one five-year term through December 2032. For accounting purposes, the natural gas purchase commitment and the term extending option has been aggregated into a single compound embedded derivative. The probability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may exist at the time they would elect whether to renew the contract. The changes in fair value of this compound embedded derivative are based on the difference between the contractual and index pricing, and the probability of the producer customer exercising its option to extend. The changes in fair value are recorded in earnings through “Purchased product costs” on the Consolidated Statements of Income. As of December 31, 2021 and 2020, the estimated fair value of this contract was a liability of $108 million and $63 million, respectively.
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Open Derivative Positions and Sensitivity Analysis
The estimated fair value of our Level 2 and 3 financial instruments are sensitive to the assumptions used in our pricing models. Sensitivity analysis of a ten percent difference in our estimated fair value of Level 2 and 3 commodity derivatives (excluding embedded derivatives) as of December 31, 2021 would not have affected income before income taxes for the year ended December 31, 2021, given we had no open commodity derivative contracts during the year. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles.
Interest Rate Risk
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on third-party outstanding debt, excluding finance leases, is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
| (In millions) | Fair Value as of December 31, 2021(1) | Change in Fair Value (2) | Change in Income before income taxes for the Year Ended December 31, 2021 (3) | |||||||||||||||||
| Outstanding debt | ||||||||||||||||||||
| Fixed-rate | $ | 20,479 | $ | 1,848 | N/A | |||||||||||||||
Variable-rate(4) | $ | 300 | $ | — | $ | 9 | ||||||||||||||
(1)Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.
(2)Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at December 31, 2021.
(3)Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the year ended December 31, 2021.
(4)MPLX redeemed the outstanding floating rate senior notes on September 3, 2021.
Our use of fixed or variable-rate debt directly exposes us to interest rate risk. Fixed rate debt, such as our senior notes, exposes us to changes in the fair value of our debt due to changes in market interest rates. Fixed rate debt also exposes us to the risk that we may need to refinance maturing debt with new debt at higher rates or that our current fixed rate debt may be higher than the current market. Variable-rate debt, such as borrowings under our revolving credit facilities, exposes us to short-term changes in market rates that impact our interest expense. A portion of our borrowing capacity and outstanding indebtedness bears interest at a variable rate based on LIBOR. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR), or FCA, announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. Subsequently, on March 5, 2021, ICE Benchmark Administration Limited (the entity that calculates and publishes LIBOR), or IBA, and FCA made public statements regarding the future cessation of LIBOR. According to the FCA, IBA will permanently cease to publish each of the LIBOR settings on either December 31, 2021 or June 30, 2023. IBA did not identify any successor administrator in its announcement. The announced final publication date for 1-week and 2-month LIBOR settings and all settings for non-USD LIBOR was December 31, 2021. The announced final publication date for overnight, 1-month, 3-month, 6-month and 12-month LIBOR settings is June 30, 2023. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after such end dates, and there is considerable uncertainty regarding the publication or representativeness of LIBOR beyond such end dates. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is seeking to replace U.S. dollar LIBOR with a newly created index (the secured overnight financing rate or SOFR), calculated based on repurchase agreements backed by treasury securities. The agreements that govern our variable rate indebtedness contain customary transition and fallback provisions in contemplation of the cessation of LIBOR. We continue to monitor developments regarding the cessation of LIBOR and transition to an alternate benchmark rate, but do not expect it to have a material impact on our financial position, results of operation or cash flows. Nevertheless, at this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere may have on LIBOR, other benchmarks or floating rate indebtedness.
Credit Risk
We are subject to risk of loss resulting from non-payment by our customers to whom we provide services, lease assets, or sell natural gas or NGLs. We believe that certain contracts where we sell NGLs and act as our producer
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customers’ agent would allow us to pass those losses through to our customers, thus reducing our risk. Our credit exposure related to these customers is represented by the value of our trade receivables or lease receivables. Where exposed to credit risk, we analyze the customer’s financial condition prior to entering into a transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively impacted.
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Item 8. Financial Statements and Supplementary Data
INDEX
| Page | ||||||||
(PCAOB ID 238) | ||||||||
| Audited Consolidated Financial Statements: | ||||||||
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Management’s Responsibilities for Financial Statements
The accompanying consolidated financial statements of MPLX LP and its subsidiaries (the “Partnership”) are the responsibility of management of the Partnership’s general partner, MPLX GP LLC, and have been prepared in conformity with accounting principles generally accepted in the United States of America. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.
MPLX GP LLC seeks to assure the objectivity and integrity of the Partnership’s financial records by careful selection of its managers, by organizational arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.
The MPLX GP LLC Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit Committee. This committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.
| /s/ Michael J. Hennigan | /s/ John J. Quaid | /s/ Kelly D. Wright | ||||||||||||
| Michael J. Hennigan Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) | John J. Quaid Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) | Kelly D. Wright Vice President and Controller of MPLX GP LLC (the general partner of MPLX LP) | ||||||||||||
Management’s Report on Internal Control over Financial Reporting
MPLX LP’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934, as amended). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our chief executive officer and chief financial officer. Based on the results of this evaluation, MPLX LP’s management concluded that its internal control over financial reporting was effective as of December 31, 2021.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2021 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
| /s/ Michael J. Hennigan | /s/ John J. Quaid | |||||||||||||
| Michael J. Hennigan Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) | John J. Quaid Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) | |||||||||||||
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Report of Independent Registered Public Accounting Firm
To the Partners of MPLX LP and the Board of Directors of MPLX GP LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of MPLX LP and its subsidiaries (the “Company”) as of December 31, 2021 and 2020, and the related consolidated statements of income, of comprehensive income, of equity and of cash flows for each of the three years in the period ended December 31, 2021, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may
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become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Goodwill Impairment Test - Crude Gathering Reporting Unit
As described in Note 14 to the consolidated financial statements, the Company’s consolidated goodwill balance was $7,657 million as of December 31, 2021. Additionally, as disclosed by management, the goodwill balance at December 31, 2021 includes goodwill associated with the Crude Gathering reporting unit of $1.1 billion. Management annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount. The fair value of each reporting unit is determined based on applying both a discounted cash flow method, or income approach, as well as a market approach. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method included management’s best estimates of the discount rate, as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact future volumes and capital requirements.
The principal considerations for our determination that performing procedures relating to the goodwill impairment test of the Crude Gathering reporting unit is a critical audit matter are the significant judgment by management when determining the fair value of the reporting unit, which led to a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence relating to management’s significant assumption related to future volumes.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment test, including controls over the determination of the fair value of the Crude Gathering reporting unit. These procedures also included, among others, testing management’s process for determining the fair value of the reporting unit; evaluating the appropriateness of the income and market approaches used; testing the completeness and accuracy of underlying data used by management in the approaches; and evaluating the reasonableness of the significant assumption related to future volumes. Evaluating the assumption related to future volumes involved (i) considering whether the assumption used was reasonable considering past performance of the reporting unit, producer customers’ historical and future production volumes, and industry outlook reports, and (ii) considering whether the assumption was consistent with evidence obtained in other areas of the audit.
/s/ PricewaterhouseCoopers LLP
Toledo, Ohio
February 24, 2022
We have served as the Company’s auditor since 2012.
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MPLX LP
Consolidated Statements of Income
| (In millions, except per unit data) | 2021 | 2020 | 2019 | |||||||||||||||||
| Revenues and other income: | ||||||||||||||||||||
| Service revenue | $ | 2,313 | $ | 2,397 | $ | 2,498 | ||||||||||||||
| Service revenue - related parties | 3,628 | 3,580 | 3,455 | |||||||||||||||||
| Service revenue - product related | 345 | 155 | 140 | |||||||||||||||||
| Rental income | 376 | 398 | 388 | |||||||||||||||||
| Rental income - related parties | 743 | 952 | 1,196 | |||||||||||||||||
| Product sales | 1,590 | 636 | 806 | |||||||||||||||||
| Product sales - related parties | 145 | 128 | 142 | |||||||||||||||||
| Sales-type lease revenue - related parties | 435 | 152 | 7 | |||||||||||||||||
| Income/(loss) from equity method investments | 321 | (936) | 290 | |||||||||||||||||
| Other income | 21 | 5 | 12 | |||||||||||||||||
| Other income - related parties | 110 | 102 | 107 | |||||||||||||||||
| Total revenues and other income | 10,027 | 7,569 | 9,041 | |||||||||||||||||
| Costs and expenses: | ||||||||||||||||||||
| Cost of revenues (excludes items below) | 1,184 | 1,326 | 1,489 | |||||||||||||||||
| Purchased product costs | 1,585 | 539 | 686 | |||||||||||||||||
| Rental cost of sales | 136 | 135 | 141 | |||||||||||||||||
| Rental cost of sales - related parties | 109 | 160 | 165 | |||||||||||||||||
| Purchases - related parties | 1,219 | 1,116 | 1,231 | |||||||||||||||||
| Depreciation and amortization | 1,287 | 1,377 | 1,254 | |||||||||||||||||
| Impairment expense | 42 | 2,165 | 1,197 | |||||||||||||||||
| General and administrative expenses | 353 | 378 | 388 | |||||||||||||||||
| Restructuring expenses | — | 37 | — | |||||||||||||||||
| Other taxes | 120 | 125 | 113 | |||||||||||||||||
| Total costs and expenses | 6,035 | 7,358 | 6,664 | |||||||||||||||||
| Income from operations | 3,992 | 211 | 2,377 | |||||||||||||||||
| Related party interest and other financial costs | 8 | 5 | 11 | |||||||||||||||||
Interest expense (net of amounts capitalized of $14 million, $39 million and $51 million, respectively) | 785 | 829 | 851 | |||||||||||||||||
| Other financial costs | 86 | 62 | 53 | |||||||||||||||||
| Income/(loss) before income taxes | 3,113 | (685) | 1,462 | |||||||||||||||||
| Provision for income taxes | 1 | 2 | — | |||||||||||||||||
| Net income/(loss) | 3,112 | (687) | 1,462 | |||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 35 | 33 | 28 | |||||||||||||||||
| Less: Net income attributable to Predecessor | — | — | 401 | |||||||||||||||||
| Net income/(loss) attributable to MPLX LP | 3,077 | (720) | 1,033 | |||||||||||||||||
| Less: Series A preferred unit distributions | 100 | 81 | 81 | |||||||||||||||||
| Less: Series B preferred unit distributions | 41 | 41 | 17 | |||||||||||||||||
| Limited partners’ interest in net (loss)/income attributable to MPLX LP | $ | 2,936 | $ | (842) | $ | 935 | ||||||||||||||
| Per Unit Data (See Note 8) | ||||||||||||||||||||
| Net income/(loss) attributable to MPLX LP per limited partner unit: | ||||||||||||||||||||
| Common - basic | $ | 2.86 | $ | (0.80) | $ | 1.00 | ||||||||||||||
| Common - diluted | $ | 2.86 | $ | (0.80) | $ | 1.00 | ||||||||||||||
| Weighted average limited partner units outstanding: | ||||||||||||||||||||
| Common - basic | 1,027 | 1,051 | 906 | |||||||||||||||||
| Common - diluted | 1,027 | 1,051 | 907 | |||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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MPLX LP
Consolidated Statements of Comprehensive Income
| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
| Net income/(loss) | $ | 3,112 | $ | (687) | $ | 1,462 | |||||||||||
| Other comprehensive income/(loss), net of tax: | |||||||||||||||||
| Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax | (2) | — | 1 | ||||||||||||||
| Comprehensive income/(loss) | 3,110 | (687) | 1,463 | ||||||||||||||
| Less comprehensive income attributable to: | |||||||||||||||||
| Noncontrolling interests | 35 | 33 | 28 | ||||||||||||||
| Income attributable to Predecessor | — | — | 401 | ||||||||||||||
| Comprehensive income/(loss) attributable to MPLX LP | $ | 3,075 | $ | (720) | $ | 1,034 | |||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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MPLX LP
Consolidated Balance Sheets
| December 31, | ||||||||||||||
| (In millions) | 2021 | 2020 | ||||||||||||
| Assets | ||||||||||||||
| Current assets: | ||||||||||||||
| Cash and cash equivalents | $ | 13 | $ | 15 | ||||||||||
| Receivables, net | 654 | 452 | ||||||||||||
| Current assets - related parties | 644 | 677 | ||||||||||||
| Inventories | 142 | 118 | ||||||||||||
| Other current assets | 54 | 65 | ||||||||||||
| Assets held for sale | — | 188 | ||||||||||||
| Total current assets | 1,507 | 1,515 | ||||||||||||
| Equity method investments | 3,981 | 4,036 | ||||||||||||
| Property, plant and equipment, net | 20,042 | 21,218 | ||||||||||||
| Intangibles, net | 831 | 959 | ||||||||||||
| Goodwill | 7,657 | 7,657 | ||||||||||||
| Right of use assets, net | 268 | 309 | ||||||||||||
| Noncurrent assets - related parties | 1,161 | 672 | ||||||||||||
| Other noncurrent assets | 60 | 48 | ||||||||||||
| Total assets | 35,507 | 36,414 | ||||||||||||
| Liabilities | ||||||||||||||
| Current liabilities: | ||||||||||||||
| Accounts payable | 172 | 152 | ||||||||||||
| Accrued liabilities | 363 | 194 | ||||||||||||
| Current liabilities - related parties | 1,780 | 356 | ||||||||||||
| Accrued property, plant and equipment | 97 | 84 | ||||||||||||
| Long-term debt due within one year | 499 | 764 | ||||||||||||
| Accrued interest payable | 202 | 222 | ||||||||||||
| Operating lease liabilities | 59 | 63 | ||||||||||||
| Other current liabilities | 176 | 150 | ||||||||||||
| Liabilities held for sale | — | 101 | ||||||||||||
| Total current liabilities | 3,348 | 2,086 | ||||||||||||
| Long-term deferred revenue | 383 | 314 | ||||||||||||
| Long-term liabilities - related parties | 302 | 283 | ||||||||||||
| Long-term debt | 18,072 | 19,375 | ||||||||||||
| Deferred income taxes | 10 | 12 | ||||||||||||
| Long-term operating lease liabilities | 205 | 244 | ||||||||||||
| Deferred credits and other liabilities | 170 | 115 | ||||||||||||
| Total liabilities | 22,490 | 22,429 | ||||||||||||
| Commitments and contingencies (see Note 21) | ||||||||||||||
| Series A preferred units | 965 | 968 | ||||||||||||
| Equity | ||||||||||||||
Common unitholders - public (369 million and 391 million units issued and outstanding) | 8,579 | 9,384 | ||||||||||||
Common unitholder - MPC (647 million and 647 million units issued and outstanding) | 2,638 | 2,792 | ||||||||||||
Series B preferred units (0.6 million and 0.6 million units issued and outstanding) | 611 | 611 | ||||||||||||
| Accumulated other comprehensive loss | (17) | (15) | ||||||||||||
| Total MPLX LP partners’ capital | 11,811 | 12,772 | ||||||||||||
| Noncontrolling interests | 241 | 245 | ||||||||||||
| Total equity | 12,052 | 13,017 | ||||||||||||
| Total liabilities, preferred units and equity | $ | 35,507 | $ | 36,414 | ||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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MPLX LP
Consolidated Statements of Cash Flows
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| Operating activities: | ||||||||||||||||||||
| Net income/(loss) | $ | 3,112 | $ | (687) | $ | 1,462 | ||||||||||||||
| Adjustments to reconcile net income/(loss) to net cash provided by operating activities: | ||||||||||||||||||||
| Amortization of deferred financing costs | 70 | 61 | 42 | |||||||||||||||||
| Depreciation and amortization | 1,287 | 1,377 | 1,254 | |||||||||||||||||
| Impairment expense | 42 | 2,165 | 1,197 | |||||||||||||||||
| Deferred income taxes | (2) | (1) | (2) | |||||||||||||||||
| Asset retirement expenditures | — | — | (1) | |||||||||||||||||
| (Gain)/loss on disposal of assets | (13) | 4 | (6) | |||||||||||||||||
| (Income)/loss from equity method investments | (321) | 936 | (290) | |||||||||||||||||
| Distributions from unconsolidated affiliates | 508 | 459 | 525 | |||||||||||||||||
| Changes in: | ||||||||||||||||||||
| Current receivables | (199) | 62 | 17 | |||||||||||||||||
| Inventories | (24) | (12) | (9) | |||||||||||||||||
| Fair value of derivatives | 45 | 3 | 2 | |||||||||||||||||
| Current accounts payable and accrued liabilities | 193 | 36 | (59) | |||||||||||||||||
| Current assets/current liabilities - related parties | 101 | 8 | (163) | |||||||||||||||||
| Right of use assets/operating lease liabilities | (2) | (5) | 4 | |||||||||||||||||
| Deferred revenue | 88 | 112 | 100 | |||||||||||||||||
| All other, net | 26 | 3 | 9 | |||||||||||||||||
| Net cash provided by operating activities | 4,911 | 4,521 | 4,082 | |||||||||||||||||
| Investing activities: | ||||||||||||||||||||
| Additions to property, plant and equipment | (529) | (1,183) | (2,408) | |||||||||||||||||
| Acquisitions, net of cash acquired | — | — | 6 | |||||||||||||||||
| Disposal of assets | 126 | 56 | 30 | |||||||||||||||||
| Investments in unconsolidated affiliates | (151) | (266) | (713) | |||||||||||||||||
| Distributions from unconsolidated affiliates - return of capital | 36 | 123 | 18 | |||||||||||||||||
| All other, net | — | 8 | 4 | |||||||||||||||||
| Net cash used in investing activities | (518) | (1,262) | (3,063) | |||||||||||||||||
| Financing activities: | ||||||||||||||||||||
| Long-term debt - borrowings | 4,175 | 6,810 | 9,174 | |||||||||||||||||
| - repayments | (5,821) | (6,414) | (7,924) | |||||||||||||||||
| Related party debt - borrowings | 8,493 | 6,264 | 9,313 | |||||||||||||||||
| - repayments | (7,043) | (6,858) | (8,719) | |||||||||||||||||
| Debt issuance costs | — | (25) | (20) | |||||||||||||||||
| Unit repurchases | (630) | (33) | — | |||||||||||||||||
| Distributions to Series A preferred unitholders | (100) | (81) | (81) | |||||||||||||||||
| Distributions to Series B preferred unitholders | (41) | (41) | (21) | |||||||||||||||||
| Distributions to unitholders and general partner | (3,432) | (2,884) | (2,435) | |||||||||||||||||
| Distributions to common and Series B preferred unitholders from Predecessor | — | — | (502) | |||||||||||||||||
| Distributions to noncontrolling interests | (39) | (37) | (30) | |||||||||||||||||
| Contributions from MPC | 45 | 50 | 74 | |||||||||||||||||
| Contributions from noncontrolling interests | — | — | 95 | |||||||||||||||||
| All other, net | (2) | (10) | (13) | |||||||||||||||||
| Net cash used in financing activities | (4,395) | (3,259) | (1,089) | |||||||||||||||||
| Net (decrease)/increase in cash, cash equivalents and restricted cash | (2) | — | (70) | |||||||||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | 15 | 15 | 85 | |||||||||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | 13 | $ | 15 | $ | 15 | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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MPLX LP
Consolidated Statements of Equity and Series A Preferred Units
| Partnership | ||||||||||||||||||||||||||||||||
| (In millions) | Common Unit-holder Public | Common Unit-holder MPC | Series B Preferred Unit-holders | Accumulated Other Comprehensive Loss | Non-controlling Interests | Equity of Predecessor | Total | Series A Preferred Unit-holders | ||||||||||||||||||||||||
| Balance at December 31, 2018 | $ | 8,336 | $ | (1,612) | $ | — | $ | (16) | $ | 156 | $ | 10,867 | $ | 17,731 | $ | 1,004 | ||||||||||||||||
| Net income | 340 | 595 | 17 | — | 28 | 401 | 1,381 | 81 | ||||||||||||||||||||||||
| Allocation of MPC's net investment at acquisition | 2,983 | 7,199 | 615 | — | — | (10,797) | — | — | ||||||||||||||||||||||||
| Conversion of Series A preferred units | 36 | — | — | — | — | — | 36 | (36) | ||||||||||||||||||||||||
| Distributions | (907) | (1,529) | (21) | — | (30) | (502) | (2,989) | (81) | ||||||||||||||||||||||||
| Contributions | — | 315 | — | — | 95 | 31 | 441 | — | ||||||||||||||||||||||||
| Other | 12 | — | — | 1 | — | — | 13 | — | ||||||||||||||||||||||||
| Balance at December 31, 2019 | 10,800 | 4,968 | 611 | (15) | 249 | — | 16,613 | 968 | ||||||||||||||||||||||||
| Net income | (307) | (535) | 41 | — | 33 | — | (768) | 81 | ||||||||||||||||||||||||
| Unit repurchases | (33) | — | — | — | — | — | (33) | — | ||||||||||||||||||||||||
| Distributions | (1,082) | (1,799) | (41) | — | (37) | — | (2,959) | (81) | ||||||||||||||||||||||||
| Contributions | — | 261 | — | — | — | — | 261 | — | ||||||||||||||||||||||||
| Wholesale Exchange | — | (102) | — | — | — | — | (102) | — | ||||||||||||||||||||||||
| Other | 6 | (1) | — | — | — | — | 5 | — | ||||||||||||||||||||||||
| Balance at December 31, 2020 | 9,384 | 2,792 | 611 | (15) | 245 | — | 13,017 | 968 | ||||||||||||||||||||||||
| Net income | 1,087 | 1,849 | 41 | — | 35 | — | 3,012 | 100 | ||||||||||||||||||||||||
| Unit repurchases | (630) | — | — | — | — | — | (630) | — | ||||||||||||||||||||||||
| Conversion of Series A preferred units | 3 | — | — | — | — | — | 3 | (3) | ||||||||||||||||||||||||
| Distributions | (1,269) | (2,163) | (41) | — | (39) | — | (3,512) | (100) | ||||||||||||||||||||||||
| Contributions | — | 160 | — | — | — | — | 160 | — | ||||||||||||||||||||||||
| Other | 4 | — | — | (2) | — | — | 2 | — | ||||||||||||||||||||||||
| Balance at December 31, 2021 | $ | 8,579 | $ | 2,638 | $ | 611 | $ | (17) | $ | 241 | $ | — | $ | 12,052 | $ | 965 | ||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
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Notes to Consolidated Financial Statements
1. Description of the Business and Basis of Presentation
Description of the Business – MPLX LP is a diversified, large-cap master limited partnership formed by Marathon Petroleum Corporation (“MPC”) that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. References in this report to “MPLX LP,” “MPLX,” “the Partnership,” “we,” “ours,” “us,” or like terms refer to MPLX LP and its subsidiaries. References to “MPC” refer collectively to Marathon Petroleum Corporation as our sponsor and its subsidiaries, other than the Partnership. We are engaged in the gathering, transportation, storage and distribution of crude oil, refined products and other hydrocarbon-based products; the gathering, processing and transportation of natural gas; and the gathering, transportation, fractionation, storage and marketing of NGLs. MPLX’s principal executive office is located in Findlay, Ohio. MPLX was formed on March 27, 2012 as a Delaware limited partnership and completed its initial public offering on October 31, 2012.
MPLX’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”), which relates primarily to crude oil, refined products and other hydrocarbon-based products; and Gathering and Processing (“G&P”), which relates primarily to natural gas and NGLs. See Note 10 for additional information regarding the operations and results of these segments.
On July 31, 2020, MPLX completed the exchange of Western Refining Wholesale, LLC (WRW”) to Western Refining Southwest, Inc. (now known as Western Refining Southwest LLC) (“WRSW”), a wholly owned subsidiary of MPC, in exchange for the redemption of 18,582,088 MPLX common units held by WRSW (the “Wholesale Exchange”). See Note 4 for additional information regarding the Wholesale Exchange. These financial statements include the results of WRSW through July 31, 2020.
On July 30, 2019, MPLX completed its acquisition of Andeavor Logistics LP (“ANDX” and such acquisition, the “Merger”). 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. See Note 4 for additional information regarding the Merger.
Basis of Presentation – The accompanying consolidated financial statements of MPLX have been prepared in accordance with GAAP. The consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties have been recorded as “Noncontrolling interests” on the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. MPLX’s investments in which MPLX exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. MPLX’s investments in a VIE in which MPLX exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method.
In relation to the Merger described above and in Note 4, ANDX’s assets, liabilities and results of operations prior to the Merger are collectively included in what we refer to as the “Predecessor” from October 1, 2018, which was the date that MPC acquired Andeavor. MPLX’s acquisition of ANDX is considered a transfer between entities under common control due to MPC’s relationship with ANDX prior to the Merger. As an entity under common control with MPC, MPLX recorded the assets acquired and liabilities assumed on its consolidated balance sheets at MPC’s historical carrying value. For the acquiring entity, transfers of businesses between entities under common control require prior periods to be retrospectively adjusted for those dates that the entity was under common control. Accordingly, the accompanying financial statements and related notes of MPLX LP have been retrospectively adjusted to include the historical results of ANDX beginning October 1, 2018.
Certain prior period financial statement amounts have been reclassified to conform to current period presentation.
2. Summary of Principal Accounting Policies
Use of Estimates – The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of
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revenues and expenses during the respective reporting periods. Actual results could differ materially from those estimates. Estimates are subject to uncertainties due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and affect items such as valuing identified intangible assets; determining the fair value of derivative instruments; evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives for long-lived assets; acquisition accounting; estimating revenues, expense accruals and capital expenditures; valuing AROs; recognizing share-based compensation expense; and determining liabilities, if any, for environmental and legal contingencies.
Revenue Recognition – Revenue is measured based on consideration specified in a contract with a customer. MPLX recognizes revenue when it satisfies a performance obligation by transferring control over a product or providing services to a customer.
MPLX enters into a variety of contract types in order to generate “Product sales” and “Service revenue.” MPLX provides services under the following types of arrangements:
•Fee-based arrangements – Under fee-based arrangements, MPLX receives a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and transportation, terminalling, storage and distribution of crude oil, refined products and other hydrocarbon-based products. The revenue MPLX earns from these arrangements is generally directly related to the volume of natural gas, NGLs, refined products or crude oil that is handled by or flows through MPLX’s systems and facilities and is not normally directly dependent on commodity prices. In certain cases, MPLX’s arrangements provide for minimum volume commitments.
•Fee-based arrangements are reported as “Service revenue” on the Consolidated Statements of Income. Revenue is recognized over time as services are performed. In certain instances when specifically stated in the contract terms, MPLX purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as “Product sales” on the Consolidated Statements of Income and recognized on a gross basis, as MPLX takes control of the product and is the principal in the transaction.
•Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, MPLX gathers and processes natural gas on behalf of producers; sells the resulting residue gas, condensate and NGLs at market prices; and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, MPLX delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes MPLX retains to third parties or related parties. Revenue is recognized on a net basis when MPLX acts as an agent and does not have control of the gross amount of gas and/or NGLs prior to it being sold. Percent-of-proceeds revenue is reported as “Service revenue - product related” on the Consolidated Statements of Income.
•Keep-whole arrangements – Under keep-whole arrangements, MPLX gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, MPLX must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the value of the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require MPLX to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. “Service revenue - product related” is recorded based on the value of the NGLs received on the date the services are performed. Natural gas purchased to return to the producer and shared NGL profits are recorded as a reduction of “Service revenue - product related” on the Consolidated Statements of Income on the date the services are performed. Sales of NGLs under these arrangements are reported as “Product sales” on the Consolidated Statements of Income and are reported on a gross basis as MPLX is the principal in the arrangement and controls the product prior to sale. The sale of the NGLs may occur shortly after services are performed at the tailgate of the plant, or after a period of time as determined by MPLX.
•Purchase arrangements – Under purchase arrangements, MPLX purchases natural gas at either the wellhead or the tailgate of a plant. MPLX then gathers and delivers the natural gas to pipelines where MPLX may resell the natural gas. Wellhead purchase arrangements represent an arrangement with a supplier and are recorded in “Purchased product costs.” Often, MPLX earns fees for services performed prior to taking control of the product in these arrangements and “Service revenue” is recorded for these fees. Revenue generated from the sale of product obtained in tailgate purchase arrangements is reported as “Product sales” on the Consolidated Statements of Income and is recognized on a gross basis as MPLX purchases and takes control of the product prior to sale and is the principal in the transaction.
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In many cases, MPLX provides services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under percent-of-proceeds arrangements, keep-whole arrangements or purchase arrangements, MPLX records such fees as “Service revenue” on the Consolidated Statements of Income. The terms of MPLX’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed, and customer requirements. Performance obligations are determined based on the specific terms of the arrangements, economics of the geographical regions, and the services offered and whether they are deemed distinct. MPLX allocates the consideration earned between the performance obligations based on the stand-alone selling price when multiple performance obligations are identified.
Revenue from MPLX’s service arrangements will generally be recognized over time as the performance obligation is satisfied as services are provided. MPLX has elected to use the output measure of progress to recognize revenue based on the units delivered, processed or transported. The transaction price has fixed components related to minimum volume commitments and variable components, which are primarily dependent on volumes. Variable consideration will generally not be estimated at contract inception as the transaction price is specifically allocable to the services provided each period. In instances in which tiered pricing structures do not reflect our efforts to perform, MPLX will estimate variable consideration at contract inception. “Product sales” will be recognized at a point in time when control of the product transfers to the customer.
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.
Amounts billed to customers for shipping and handling, electricity, and other costs to perform services are included in “Service revenue” on the Consolidated Statements of Income. Shipping and handling costs associated with product sales are included in “Purchased product costs” on the Consolidated Statements of Income. Facility expenses, costs of revenues and depreciation represent those expenses related to operating our various facilities and are necessary to provide both “Product sales” and “Service revenue.”
Customers usually pay monthly based on the products purchased or services performed that month. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue.
Based on the terms of certain natural gas gathering, transportation and processing agreements, MPLX is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. Revenue and costs related to the portion of the revenue earned under these contracts considered to be implicit leases are recorded as “Rental income” and “Rental cost of sales,” respectively, on the Consolidated Statements of Income.
Revenue and Expense Accruals – MPLX routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third-party information and reconciling MPLX’s records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries, and other operating expenses. MPLX makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are adjusted when actual information is received from third parties and MPLX’s internal records have been reconciled.
Cash and Cash Equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with initial maturities of three months or less.
Restricted Cash – Restricted cash consists of cash and investments that must be maintained as collateral for letters of credit issued to certain third-party producer customers. The balances will be outstanding until certain capital projects are completed and the third party releases the restriction. Restricted cash also consists of cash advances to be used for the operation and maintenance of an operated pipeline system. MPLX had no restricted cash as of the years ended December 31, 2021 or 2020.
Receivables – Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced amount and generally do not bear interest. Allowances for doubtful accounts are generally recorded when it becomes probable that the receivable will not be collected and are recorded to bad debt expense. We review the allowance quarterly with past-due balances over 90 days and other higher-risk amounts being reviewed individually
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for collectability. Balances that remain outstanding after reasonable collection efforts have been unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable.
Leases – As part of the adoption of ASU No. 2016-02, Leases (“ASC 842”), we elected the package of practical expedients permitted under the transition guidance within the new standard, which among other things, allowed us to grandfather the historical accounting conclusions until a reassessment event is present. We also elected the practical expedient to not recognize short-term leases on the balance sheet, the practical expedient related to right of way permits and land easements which allows us to carry forward our accounting treatment for those existing agreements, and the practical expedient to combine lease and non-lease components for the majority of our underlying classes of assets except for our third-party contractor service and equipment agreements and boat and barge equipment agreements in which we are the lessee. We did not elect the practical expedient to combine lease and non-lease components for arrangements in which we are the lessor. In instances where the practical expedient was not elected, lease and non-lease consideration is allocated based on relative standalone selling price.
Right of use (“ROU”) assets represent our right to use an underlying asset in which we obtain substantially all of the economic benefits and the right to direct the use of the asset during the lease term. Lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease ROU assets and lease liabilities are recognized at the commencement date based on the present value of lease payments over the lease term. We recognize ROU assets and lease liabilities on the balance sheet for leases with a lease term of greater than one year. Payments that are not fixed at the commencement of the lease are considered variable and are excluded from the ROU asset and lease liability calculations. In the measurement of our ROU assets and lease liabilities, the fixed lease payments in the agreement are discounted using a secured incremental borrowing rate for a term similar to the duration of the lease, as our leases do not provide implicit rates. Operating lease expense is recognized on a straight-line basis over the lease term.
As a lessor under ASC 842, MPLX may be required to re-classify existing operating leases to sales-type leases upon modification and related reassessment of the leases. See Note 20 for further information regarding our ongoing evaluation of the impacts of lease reassessments as modifications occur. The net investment in a sales-type lease is recorded within “Current assets - related parties” and “Noncurrent assets - related parties” on the Consolidated Balance Sheets and is comprised of the present value of the sum of the future minimum lease payments representing the value of the lease receivable and the unguaranteed residual value of the leased assets. Management assesses the net investment in sales-type leases for recoverability quarterly.
Inventories – Inventories consist of materials and supplies to be used in operations, line fill and other NGLs. Cost for materials and supplies are determined primarily using the weighted-average cost method. Inventories are valued at the lower of cost or market value.
Imbalances – Within our pipelines and storage assets, we experience volume gains and losses due to pressure and temperature changes, evaporation and variances in meter readings and other measurement methods. Until settled, positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a different source, or tracked and settled in the future.
Property, Plant and Equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Expenditures that extend the useful lives of assets are capitalized. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment assessment is performed and the excess of the book value over the fair value is recorded as an impairment loss.
When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported on the Consolidated Statements of Income. Gains on the disposal of property, plant and equipment are recognized when they occur, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale.
Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset’s estimated useful life.
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Goodwill and Intangibles – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined using an income and/or market approach which is compared to the carrying value of the reporting unit. The fair value under the income approach is calculated using the expected present value of future cash flows method. Significant assumptions used in the cash flow forecasts include future operating performance, future volumes, discount rates, and future capital requirements. If the fair value of the reporting unit is less than the carrying value, including goodwill, the excess, if any, of the book value over the fair value of the reporting unit up to the amount of goodwill recorded is charged to net income as an impairment expense. See Note 14 for further details.
Amortization of intangibles with definite lives is calculated using the straight-line method, which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangibles subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.
Other Taxes – Other taxes primarily include real estate taxes.
Environmental Costs – Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. MPLX recognizes remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.
Asset Retirement Obligations – An ARO is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate and increases due to the passage of time based on the time value of money until the obligation is settled. AROs have not been recognized for certain assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. At December 31, 2021, MPLX’s asset retirement obligation was $31 million, which is included on the balance sheet within “Deferred credits and other liabilities.”
Investment in Unconsolidated Affiliates – Equity investments in which MPLX exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method and are reported in “Equity method investments” on the accompanying Consolidated Balance Sheets. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights. Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill.
MPLX believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. MPLX uses evidence of a loss in value to identify if an investment has an other than a temporary decline. Impairments are recorded through “Income from equity method investments.”
Derivative Instruments – MPLX may use commodity derivatives to economically hedge a portion of its exposure to commodity price risk. All derivative instruments (including derivatives embedded in other contracts) are recorded at fair value. Certain commodity derivatives are reflected on the consolidated balance sheets on a net basis by counterparty as they are governed by master netting arrangements. MPLX discloses the fair value of all derivative
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instruments under the captions “Other current assets” “Other noncurrent assets,” “Other current liabilities” and “Deferred credits and other liabilities” on the Consolidated Balance Sheets. Changes in the fair value of derivative instruments are reported on the Consolidated Statements of Income in accounts related to the item whose value or cash flows are being managed. All derivative instruments are marked to market through “Product sales,” “Purchased product costs,” or “Cost of revenues” on the Consolidated Statements of Income. Revenue gains and losses relate to contracts utilized to manage the cash flow for the sale of a product, typically NGLs. Purchased product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically related to keep-whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.
MPLX did not utilize any commodity derivatives during the years ended December 31, 2021, 2020 and 2019, and therefore did not elect hedge accounting. MPLX has historically elected the normal purchases and normal sales designation for certain contracts related to the physical purchase of electric power and the sale of some commodities.
Fair Value Measurement – Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon the fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into Level 1, Level 2 or Level 3. A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The methods and assumptions utilized may produce a fair value that may not be realized in future periods upon settlement. Furthermore, while MPLX believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion, see Note 15.
Equity-Based Compensation Arrangements – MPLX issues phantom units under the MPLX LP 2018 Incentive Compensation Plan. A phantom unit entitles the grantee a right to receive a common unit upon the issuance of the phantom unit. The fair value of phantom unit awards granted to employees and non-employee directors is based on the fair market value of MPLX LP common units on the date of grant. The fair value of the units awarded is amortized into earnings using a straight-line amortization schedule over the period of service corresponding with the vesting period. For phantom units that vest immediately and are not forfeitable, equity-based compensation expense is recognized at the time of grant.
MPLX previously issued performance units under the MPLX LP 2018 Incentive Compensation Plan. Performance units paying out in cash are accounted for as liability awards and recorded at fair value with a mark-to-market adjustment made each quarter. The performance units paying out in units are accounted for as equity awards. Equity-classified performance units with a market condition use a Monte Carlo valuation model to calculate a grant date fair value of market conditions. Equity-classified performance units with a performance condition are valued based on the grant date fair value of the payout deemed most probable to occur and is adjusted as the expectation for payout changes.
To satisfy common unit awards, MPLX may issue new common units, acquire common units in the open market or use common units already owned by the general partner.
Income Taxes – MPLX is not a taxable entity for United States federal income tax purposes or for the majority of the states that impose an income tax. Taxes on MPLX’s net income generally are borne by its partners through the allocation of taxable income. MPLX’s taxable income or loss, which may vary substantially from the net income or loss reported on the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. MPLX and certain legal entities are, however, taxable entities under certain state jurisdictions.
MPLX accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized as tax expense/(benefit) from continuing operations in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as
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determined by management. All deferred tax balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among operations and items charged or credited directly to equity.
Distributions – In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to Series A and Series B preferred unitholders based on a fixed distribution schedule, as discussed in Notes 7 and 9, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued as a liability until declared. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described below.
Net Income Per Limited Partner Unit – MPLX uses the two-class method when calculating the net income per unit applicable to limited partners, because there is more than one class of participating security. The classes of participating securities include common units, Series A and Series B preferred units and certain equity-based compensation awards.
Net income attributable to MPLX LP is allocated to the unitholders differently for preparation of the Consolidated Statements of Equity and the calculation of net income per limited partner unit. In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to Series A and Series B preferred unitholders based on a fixed distribution schedule and subsequently allocated to remaining unitholders in accordance with their respective ownership percentages. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 8.
In preparing net income per limited partner units, during periods in which a net loss attributable to MPLX is reported or periods in which the total distributions exceed the reported net income attributable to MPLX’s unitholders, the amount allocable to certain equity-based compensation awards is based on actual distributions to the equity-based compensation awards. Diluted earnings per unit is calculated by dividing net income attributable to MPLX’s common unitholders, after deducting amounts allocable to other participating securities, by the weighted average number of common units and potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which net income attributable to MPLX’s unitholders, after deducting amounts that are allocable to the outstanding equity-based compensation awards and preferred units, is a loss, as the impact would be anti-dilutive.
Business Combinations – MPLX recognizes and measures the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. Depending on the nature of the transaction, management may engage an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interests, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, MPLX will record any material adjustments to the initial estimate based on new information obtained that would have existed as of the acquisition date. An adjustment that arises from information obtained that did not exist as of the date of the acquisition will be recorded in the period of the adjustment. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interests, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of volumes, certain commodity prices, revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. Acquisition-related costs are expensed as incurred in connection with each business combination.
Acquisitions in which the company or business being acquired by MPLX had an existing relationship with MPC may result in the transaction being considered a transfer between entities under common control. In this situations, MPLX records the assets acquired and liabilities assumed on its consolidated balance sheets at MPC’s historical carrying value. For the acquiring entity, transfers of businesses between entities under common control require prior periods to be retrospectively adjusted for those dates that the entity was under common control. See Note 4 for more information about the acquisitions.
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3. Accounting Standards
Recently Adopted
We did not adopt any ASUs during 2021 that are expected to have a material impact to our financial statements or financial statement disclosures.
Not Yet Adopted
ASU 2021-10, Government Assistance (Topic 832): Disclosures by Business Entities about Government Assistance
In November 2021, the FASB issued guidance requiring disclosures for certain types of government assistance that have been accounted for by analogy to grant or contribution models. Disclosures will include information about the type of transactions, accounting and the impact on financial statements. Guidance must be applied to our annual financial statements for year ended 2022 either prospectively for any transactions reflected in the financial statement at the date of initial application and to any new transactions entered into after the date of initial application or retrospectively to those transactions. Early application is permitted. While we are still evaluating the impact of ASU 2021-10, we do not expect to the adoption of this standard to have a material impact on our consolidated financial statements.
4. Acquisitions and Dispositions
Sale of Javelina
On February 12, 2021, MarkWest Energy Operating Company, L.L.C., (“MarkWest Energy”) a wholly owned subsidiary of MPLX, completed the sale of all of MarkWest Energy’s equity interests in MarkWest Javelina Company L.L.C., MarkWest Javelina Pipeline Company L.L.C., and MarkWest Gas Services L.L.C. (collectively, “Javelina”) pursuant to the terms of an Equity Purchase Agreement entered into with a third party on December 23, 2020. The agreement included adjustments for working capital as well as an earnout provision based on the performance of the assets. No gain or loss was recorded on the sale. The estimated value of the earnout provision was recorded as a contingent asset shown within “Other noncurrent assets” on the Consolidated Balance Sheets as of December 31, 2021. Javelina’s assets and liabilities sold are shown on the Consolidated Balance Sheet as “Assets held for sale” and “Liabilities held for sale”, respectively, for the year ended December 31, 2020. Prior to the sale, Javelina was reported within the G&P segment.
Wholesale Exchange
On July 31, 2020, MPLX entered into a Redemption Agreement (the “Redemption Agreement”) with WRSW, a wholly owned subsidiary of MPC, pursuant to which MPLX agreed to transfer to WRSW all of the outstanding membership interests in WRW in exchange for the redemption of MPLX common units held by WRSW. The transaction effects the transfer to MPC of the Western wholesale distribution business that MPLX acquired as a result of its acquisition of ANDX as described below. Per the terms of the Redemption Agreement, MPLX redeemed 18,582,088 common units (the “Redeemed Units”) held by WRSW on July 31, 2020. The number of Redeemed Units was calculated by dividing WRW’s aggregate valuation of $340 million by the simple average of the volume weighted average NYSE prices of an MPLX common unit for the ten trading days ending at market close on July 27, 2020. MPLX canceled the Redeemed Units immediately following the Wholesale Exchange. The carrying value of the net assets of WRW transferred to MPC was approximately $90 million as of July 31, 2020, resulting in $250 million being recorded to “Common Unit-holder MPC” within the Consolidated Statements of Equity, netted against the fair value of the redeemed units. Included within the $90 million carrying value of the WRW net assets was approximately $65 million of goodwill.
Acquisition of Andeavor Logistics LP
On May 7, 2019, ANDX, Tesoro Logistics GP, LLC, then the general partner of ANDX, MPLX, MPLX GP LLC, the general partner of MPLX (“MPLX GP”), and MPLX MAX LLC, a wholly owned subsidiary of MPLX (“Merger Sub”), entered into an Agreement and Plan of Merger (the “Merger Agreement”) that provided for, among other things, the merger of Merger Sub with and into ANDX. On July 30, 2019, the Merger was completed, and ANDX survived the Merger as a wholly owned subsidiary of MPLX. At the effective time of the Merger, each common unit held by
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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. See Note 7 for information on common units issued in connection with the Merger as well as Series B preferred units.
As a result of the Merger, the ANDX Special Limited Partner Interest outstanding immediately prior to the effective time of the Merger was converted into a right for WRSW, as the holder of all such interest, to receive a substantially equivalent special limited partner interest in MPLX (the “MPLX Special Limited Partner Interest”). By virtue of the conversion, the ANDX Special Limited Partner Interest was cancelled and ceased to exist as of the effective time of the Merger. For information on ANDX’s preferred units, please see Note 7.
The assets of ANDX consist of a network of owned and operated crude oil, refined product and natural gas pipelines; crude oil and water gathering systems; refining logistics assets; terminals with crude oil and refined products storage capacity; rail facilities; marine terminals including storage; bulk petroleum distribution facilities; a trucking fleet; and natural gas processing and fractionation complexes. The assets are located in the western and inland regions of the United States and complement MPLX’s existing business and assets.
MPC accounted for its October 1, 2018 acquisition of Andeavor (through which it acquired control of ANDX) using the acquisition method of accounting, which required Andeavor assets and liabilities to be recorded by MPC at the acquisition date fair value. The Merger was closed on July 30, 2019, and the results of ANDX have been incorporated into the results of MPLX as of October 1, 2018, which is the date that common control was established. As a result of MPC’s relationship with both MPLX and ANDX, the Merger has been treated as a common control transaction, which requires the recasting of MPLX’s historical results and the recognition of assets acquired and liabilities assumed using MPC’s historical carrying value.
Acquisition Costs
We recognized $14 million in acquisition costs during 2019, which are reflected in general and administrative expenses.
ANDX Revenue and Net Income
For the year ended December 31, 2019, we recognized $2.4 billion of revenues and other income related to ANDX and $266 million of net loss related to ANDX, which was impacted by the goodwill impairment discussed in Note 14.
Pro Forma Financial Information
Pro forma net income attributable to MPLX for the year ended December 31, 2019, including the historical operations of ANDX, giving effect to the merger as if it had been in effect for the full year 2019 was $1,434 million.
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5. Investments and Noncontrolling Interests
The following table presents MPLX’s equity method investments at the dates indicated:
| Ownership as of | Carrying value at | ||||||||||||||||
| December 31, | December 31, | ||||||||||||||||
| (In millions, except ownership percentages) | 2021 | 2021 | 2020 | ||||||||||||||
| L&S | |||||||||||||||||
MarEn Bakken Company LLC(1) | 25% | $ | 449 | $ | 465 | ||||||||||||
| Illinois Extension Pipeline Company, L.L.C. | 35% | 243 | 254 | ||||||||||||||
| LOOP LLC | 41% | 265 | 252 | ||||||||||||||
Andeavor Logistics Rio Pipeline LLC(2) | 67% | 183 | 194 | ||||||||||||||
| Minnesota Pipe Line Company, LLC | 17% | 183 | 188 | ||||||||||||||
Whistler Pipeline LLC(2) | 38% | 155 | 185 | ||||||||||||||
W2W Holdings LLC(2) | 50% | 58 | 72 | ||||||||||||||
| Explorer Pipeline Company | 25% | 66 | 72 | ||||||||||||||
Other(2) | 116 | 103 | |||||||||||||||
| Total L&S | 1,718 | 1,785 | |||||||||||||||
| G&P | |||||||||||||||||
MarkWest Utica EMG, L.L.C.(2) | 57% | 680 | 698 | ||||||||||||||
Sherwood Midstream LLC(2) | 50% | 544 | 557 | ||||||||||||||
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.(2) | 67% | 332 | 307 | ||||||||||||||
MarkWest Torñado GP, L.L.C.(2) | 60% | 246 | 188 | ||||||||||||||
Rendezvous Gas Services, L.L.C.(2) | 78% | 147 | 159 | ||||||||||||||
Sherwood Midstream Holdings LLC(2) | 51% | 136 | 148 | ||||||||||||||
| Centrahoma Processing LLC | 40% | 133 | 145 | ||||||||||||||
Other(2) | 45 | 49 | |||||||||||||||
| Total G&P | 2,263 | 2,251 | |||||||||||||||
| Total | $ | 3,981 | $ | 4,036 | |||||||||||||
(1) The investment in MarEn Bakken Company LLC includes our 9.19 percent indirect interest in a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system or DAPL.
(2) Investments deemed to be VIEs. Some investments included within “Other” have also been deemed to be VIEs.
For those entities that have been deemed to be VIEs, neither MPLX nor any of its subsidiaries have been deemed to be the primary beneficiary due to voting rights on significant matters. While we have the ability to exercise influence through participation in the management committees which make all significant decisions, we have equal influence over each committee as a joint interest partner and all significant decisions require the consent of the other investors without regard to economic interest and as such we have determined that these entities should not be consolidated and apply the equity method of accounting with respect to our investments in each entity.
Sherwood Midstream LLC (“Sherwood Midstream”) has been deemed the primary beneficiary of Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”) due to its controlling financial interest through its authority to manage the joint venture. As a result, Sherwood Midstream consolidates Sherwood Midstream Holdings. Therefore, MPLX also reports its portion of Sherwood Midstream Holdings’ net assets as a component of its investment in Sherwood Midstream. As of December 31, 2021, MPLX had a 24.55 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.
MPLX’s maximum exposure to loss as a result of its involvement with equity method investments includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. MPLX did not provide any financial support to equity method investments that it was not contractually obligated to provide during the years ended December 31, 2021, 2020 and 2019.
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During the first quarter of 2020, we recorded an other than temporary impairment for three joint ventures in which we have an interest. Impairment of these investments was $1,264 million, of which $1,251 million was related to MarkWest Utica EMG, L.L.C. and its investment in Ohio Gathering Company, L.L.C. The fair value of the investments was determined based upon applying the discounted cash flow method, which is an income approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future cash flows, including prices and volumes, the weighted average cost of capital and the long-term growth rate. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of these equity method investments represents a Level 3 measurement. As a result, there can be no assurance that the estimates and assumptions made for purposes of the impairment test will prove to be an accurate prediction of the future. The impairment was recorded through “Income from equity method investments.” The impairments were largely due to a reduction in forecasted volumes gathered and processed by the systems operated by the joint ventures. There were no additional impairments recorded during the remainder of 2020.
During the fourth quarter of 2019, two joint ventures in which we have an interest recorded impairments, which impacted the amount of income from equity method investments during the period by approximately $28 million and took the carrying value of one of the investments to zero. For the other joint venture, we had a basis difference recorded which was being amortized over the life of the underlying assets. As a result of the impairment recorded by the joint venture, we assessed our investment, including the related basis difference, for impairment and recorded an additional $14 million of impairment during the quarter related to our basis difference. The fair value of the investment was determined based upon applying the discounted cash flow method, which is an income approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability-weighted average set of cash flow forecasts and the discount rate. The impairment of the basis difference was also recorded through “Income from equity method investments” for a total impact during the quarter of approximately $42 million. The impairments were largely due to a reduction in forecasted volumes of the joint ventures.
Summarized financial information for MPLX’s equity method investments for the years ended December 31, 2021, 2020 and 2019 is as follows:
| December 31, 2021 | |||||||||||||||||
| (In millions) | Other VIEs | Non-VIEs | Total | ||||||||||||||
| Revenues and other income | $ | 820 | $ | 1,236 | $ | 2,056 | |||||||||||
| Costs and expenses | 490 | 568 | 1,058 | ||||||||||||||
| Income from operations | 330 | 668 | 998 | ||||||||||||||
| Net income | 266 | 594 | 860 | ||||||||||||||
Income from equity method investments(1) | $ | 175 | $ | 146 | $ | 321 | |||||||||||
| December 31, 2020 | |||||||||||||||||
| (In millions) | Other VIEs | Non-VIEs | Total | ||||||||||||||
| Revenues and other income | $ | 298 | $ | 1,208 | $ | 1,506 | |||||||||||
| Costs and expenses | 414 | 531 | 945 | ||||||||||||||
| (Loss)/income from operations | (116) | 677 | 561 | ||||||||||||||
| Net (loss)/income | (175) | 615 | 440 | ||||||||||||||
(Loss)/income from equity method investments(1) | $ | (1,100) | $ | 164 | $ | (936) | |||||||||||
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December 31, 2019(2) | |||||||||||||||||
| (In millions) | Other VIEs | Non-VIEs | Total | ||||||||||||||
| Revenues and other income | $ | 650 | $ | 1,417 | $ | 2,067 | |||||||||||
| Costs and expenses | 375 | 568 | 943 | ||||||||||||||
| Income from operations | 275 | 849 | 1,124 | ||||||||||||||
| Net income | 215 | 752 | 967 | ||||||||||||||
Income from equity method investments(1) | $ | 103 | $ | 187 | $ | 290 | |||||||||||
(1) The 2021, 2020 and 2019 amounts include impairment of $6 million, $1,264 million and $42 million, respectively.
(2) The financial information for equity method investments for 2019 includes financial information of equity method investments acquired as part of the Merger.
Summarized balance sheet information for MPLX’s equity method investments as of December 31, 2021 and 2020 is as follows:
| December 31, 2021 | |||||||||||||||||
| (In millions) | Other VIEs | Non-VIEs | Total | ||||||||||||||
| Current assets | $ | 335 | $ | 411 | $ | 746 | |||||||||||
| Noncurrent assets | 7,439 | 4,895 | 12,334 | ||||||||||||||
| Current liabilities | 217 | 310 | 527 | ||||||||||||||
| Noncurrent liabilities | $ | 2,461 | $ | 788 | $ | 3,249 | |||||||||||
| December 31, 2020 | |||||||||||||||||
| (In millions) | Other VIEs | Non-VIEs | Total | ||||||||||||||
| Current assets | $ | 530 | $ | 318 | $ | 848 | |||||||||||
| Noncurrent assets | 6,889 | 4,997 | 11,886 | ||||||||||||||
| Current liabilities | 323 | 187 | 510 | ||||||||||||||
| Noncurrent liabilities | $ | 1,904 | $ | 830 | $ | 2,734 | |||||||||||
As of December 31, 2021 and 2020, the underlying net assets of MPLX’s investees in the G&P segment exceeded the carrying value of its equity method investments by approximately $54 million and $57 million, respectively. As of December 31, 2021 and 2020, the carrying value of MPLX’s equity method investments in the L&S segment exceeded the underlying net assets of its investees by $327 million and $331 million, respectively.
At both December 31, 2021 and 2020, the G&P basis difference related to goodwill was $31 million. At both December 31, 2021 and 2020, the L&S basis difference related to goodwill was $167 million.
6. Related Party Agreements and Transactions
MPLX engages in transactions with both MPC and certain of its equity method investments as part of its normal business; however, transactions with MPC make up the majority of MPLX’s related party transactions. Transactions with related parties are further described below.
MPLX has various long-term, fee-based commercial agreements with MPC. Under these agreements, MPLX provides transportation, gathering, terminal, fuels distribution, marketing, storage, management, operational and other services to MPC. MPC has committed to provide MPLX with minimum quarterly throughput volumes on crude oil and refined products and other fees for storage capacity; operating and management fees; as well as reimbursements for certain direct and indirect costs. 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 service agreement. In addition, MPLX has obligations to MPC for services provided to MPLX by MPC under omnibus and employee services type agreements as well as other various agreements as discussed below.
The commercial agreements with MPC include:
•MPLX has a fuels distribution agreement with MPC under which MPC pays MPLX a tiered monthly volume-based fee for marketing and selling MPC’s products. This agreement is subject to a minimum quarterly
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volume and has an initial term of 10 years, subject to a year renewal period under terms to be renegotiated at that time.
•MPLX has various pipeline transportation agreements under which MPC pays MPLX fees for transporting crude and refined products on MPLX’s pipeline systems. These agreements are subject to minimum throughput volumes under which MPC will pay MPLX deficiency payments for any period in which they do not ship the minimum committed volume. These deficiency payments can be applied as credits to future periods in which MPC ships volumes in excess of the minimum volume, subject to a limited period of time. These agreements are subject to various terms and renewal periods.
•MPLX has a marine transportation agreement with an initial term of six years under which MPC pays MPLX fees for providing marine transportation of crude oil, feedstock and refined petroleum products, and related services. This agreement is subject to two automatic renewal periods of five years each. This agreement is currently in the first renewal term.
•MPLX has a month-to-month trucking transportation services agreement under which MPC pays MPLX fees for gathering barrels and providing trucking, dispatch, delivery and data services.
•MPLX has numerous storage services agreements governing storage services at various types of facilities including terminals, pipeline tank farms, caverns and refineries, under which MPC pays MPLX per-barrel fees for providing storage services. Some of these agreements provide MPC with exclusive access to storage at certain locations, such as storage located at MPC’s refineries or storage in certain caverns. Under these agreements, MPC pays MPLX a per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity. Many of the refinery storage agreements also contain provisions for logistical services to be provided by MPLX, for which MPC pays monthly fees. These agreements are subject to various terms and renewal periods.
•MPLX has multiple terminal services agreements governing certain terminals under which MPC pays MPLX fees for terminal services for refined petroleum products. Under these agreements MPC pays MPLX agreed upon fees relating to MPC product receipts, deliveries and storage as well as any blending, additization, handling, transfers or other related charges. Many of these agreements are subject to minimum volume throughput commitments, or to various minimum commitments related to some or all terminal activities, under which MPC pays a deficiency payment for any period in which they do not meet the minimum commitment. Some of these agreements allow for deficiency payments to be applied as credits to a limited number of future periods with excess throughput volumes. These agreements are subject to various terms and renewal periods.
•MPLX has a year to year keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGLs related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provides for a base volume subject to a base rate and incremental volumes subject to variable rates which are calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes are subject to revision each year.
In many cases, agreements are location-based hybrid agreements, containing provisions relating to multiple of the types of agreements and services described above.
Operating Agreements
MPLX operates various pipelines owned by MPC under operating services agreements. Under these operating services agreements, MPLX receives an operating fee for operating the assets and is reimbursed for all direct and indirect costs associated with operating the assets. Most of these agreements are indexed for inflation. These agreements range from to five years in length and automatically renew unless terminated by either party.
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Co-location Services Agreements
MPLX is party to co-location services agreements with MPC’s refineries, under which MPC provides management, operational and other services to the subsidiaries of MPLX Refining Logistics LLC (“Refining Logistics”). Refining Logistics pays MPC monthly fixed fees and direct reimbursements for such services calculated as set forth in the agreements. These agreements have initial terms of 50 years.
Ground Lease Agreements
MPLX is party to ground lease agreements with certain of MPC’s refineries under which MPLX is the lessor of certain sections of property which contain facilities owned by Refining Logistics and are within the premises of MPC’s refineries. Refining Logistics pays MPC monthly fixed fees under these ground leases. These agreements are subject to various terms.
Marine Services Agreements with MPC
MPLX has a management services agreement and a loss control agreement with MPC under which it provides management and loss control services to assist MPC in the oversight and management of the marine business. MPLX receives fixed annual fees for providing the required services, which are subject to predetermined annual escalation rates. These agreements are subject to initial terms of five years and automatically renew for one additional -year renewal period unless terminated by either party.
Omnibus Agreements
MPLX has omnibus agreements with MPC that address MPLX’s payment of fixed annual fees to MPC for the provision of executive management services by certain executive officers of the general partner and MPLX’s reimbursement of MPC for the provision of certain general and administrative services to it. They also provide for MPC’s indemnification to MPLX for certain matters, including environmental, title and tax matters; as well as our indemnification of MPC for certain matters under these agreements.
Employee Services Agreements
MPLX has various employee services agreements and secondment agreements with MPC under which MPLX reimburses MPC for employee benefit expenses, along with the provision of operational and management services in support of both our L&S and G&P segments’ operations.
Loan Agreement
MPLX is party to a loan agreement (the “MPC Loan Agreement”) with MPC Investment LLC (“MPC Investment”), a wholly owned subsidiary of MPC. Under the terms of the MPC Loan Agreement, MPC Investment extends loans to MPLX on a revolving basis as requested by MPLX and as agreed to by MPC Investment. The MPC Loan Agreement has a borrowing capacity of $1.5 billion in aggregate principal amount of all loans outstanding at any one time. The MPC Loan Agreement is scheduled to expire, and borrowings under the MPC Loan Agreement are scheduled to mature and become due and payable on July 31, 2024, provided that MPC Investment may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to the maturity date. Borrowings under the MPC Loan Agreement prior to July 31, 2019 bore interest at LIBOR plus 1.50 percent, while borrowings as of and after July 31, 2019 will bear interest at the one-month LIBOR plus 1.25 percent or such lower rate as would be applicable to such
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loans under the MPLX Credit Agreement as discussed in Note 17. Activity on the MPC Loan Agreement was as follows:
| (In millions, except %) | December 31, 2021 | December 31, 2020 | |||||||||
| Borrowings | $ | 8,493 | $ | 6,264 | |||||||
| Average interest rate of borrowings | 1.341 | % | 2.278 | % | |||||||
| Repayments | $ | 7,043 | $ | 6,858 | |||||||
| Outstanding balance at end of period | $ | 1,450 | $ | — | |||||||
Related Party Revenue
Related party sales to MPC consist of crude oil and refined products pipeline and trucking transportation services based on tariff/contracted rates; storage, terminal and fuels distribution services based on contracted rates; and marine transportation services. Related party sales to MPC also consist of revenue related to volume deficiency credits.
MPLX also has operating agreements with MPC under which it receives a fee for operating MPC’s retained pipeline assets and a fixed annual fee for providing oversight and management services required to run the marine business. MPLX also receives management fee revenue for engineering, construction and administrative services for operating certain of its equity method investments.
There were additional product sales to MPC that net to zero within the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For the years ended December 31, 2021, 2020 and 2019, these sales totaled $811 million, $462 million and $1,120 million, respectively.
Related Party Expenses
MPC provides executive management services and certain general and administrative services to MPLX under the terms of our omnibus agreements. Omnibus charges included in “Rental cost of sales - related parties” primarily relate to services that support MPLX’s rental operations and maintenance of assets available for rent, as well as compensation expenses. Omnibus charges included in “Purchases - related parties” primarily relate to services that support MPLX’s operations and maintenance activities, as well as compensation expenses. Omnibus charges included in “General and administrative expenses” primarily relate to services that support MPLX’s executive management, accounting and human resources activities. MPLX also obtains employee services from MPC under employee services agreements (“ESA charges”). ESA charges for personnel directly involved in or supporting operations and maintenance activities related to rental services are classified as “Rental cost of sales - related parties.” ESA charges for personnel directly involved in or supporting operations and maintenance activities related to other services are classified as “Purchases - related parties.” ESA charges for personnel involved in executive management, accounting and human resources activities are classified as “General and administrative expenses.” In addition to these agreements, MPLX purchases products from MPC, makes payments to MPC in its capacity as general contractor to MPLX, and has certain rent and lease agreements with MPC.
MPC has also been advancing certain strategic priorities to lay a foundation for long-term success, including plans to optimize its assets and structurally lower costs in 2021 and beyond, which included an involuntary workforce reduction plan. The workforce reduction plan, together with employee reductions resulting from MPC's indefinite idling of its Martinez, California and Gallup, New Mexico refineries, affected approximately 2,050 employees. All of the employees that conduct MPLX’s business are directly employed by affiliates of MPC, and certain of those employees were affected by MPC’s workforce reductions. During 2020, MPLX reimbursed MPC for $37 million related to severance and employee benefits related expenses that MPC recorded in connection with its workforce reductions. These costs are shown on the Consolidated Statements of Income as “Restructuring expenses.” There were no similar costs in 2021.
For the years ended December 31, 2021, 2020 and 2019, “General and administrative expenses” incurred from MPC totaled $250 million, $254 million and $243 million, respectively.
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Some charges incurred under the omnibus and employee service agreements are related to engineering services and are associated with assets under construction. These charges are added to “Property, plant and equipment, net” on the Consolidated Balance Sheets. For 2021, 2020 and 2019, these charges totaled $55 million, $97 million and $169 million, respectively.
Related Party Assets and Liabilities
Assets and liabilities with related parties appearing on the Consolidated Balance Sheets are detailed in the table below. This table identifies the various components of related party assets and liabilities, including those associated with leases (see Note 20 for additional information) and deferred revenue on minimum volume commitments. If MPC fails to meet its minimum committed volumes, MPC will pay MPLX a deficiency payment based on the terms of the agreement. The deficiency amounts received under these agreements (excluding payments received under agreements classified as sales-type leases) are recorded as “Current liabilities - related parties.” In many cases, MPC may then apply the amount of any such deficiency payments as a credit for volumes in excess of its minimum volume commitment in future periods under the terms of the applicable agreements. MPLX recognizes related party revenues for the deficiency payments when credits are used for volumes in excess of minimum quarterly volume commitments, where it is probable the customer will not use the credit in future periods or upon the expiration of the credits. The use or expiration of the credits is a decrease in “Current liabilities - related parties.” Deficiency payments under agreements that have been classified as sales-type leases are recorded as a reduction against the corresponding lease receivable. In addition, capital projects MPLX undertakes at the request of MPC are reimbursed in cash and recognized as revenue over the remaining term of the applicable agreements or in some cases, as a contribution from MPC.
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| December 31, | |||||||||||
| (In millions) | 2021 | 2020 | |||||||||
| Current assets - related parties | |||||||||||
| Receivables - MPC | $ | 548 | $ | 615 | |||||||
| Receivables - Other | 7 | 27 | |||||||||
| Prepaid - MPC | 4 | 4 | |||||||||
| Other - MPC | 3 | 1 | |||||||||
| Lease Receivables - MPC | 82 | 30 | |||||||||
| Total | 644 | 677 | |||||||||
| Noncurrent assets - related parties | |||||||||||
| Long-term receivables - MPC | 31 | 32 | |||||||||
| Right of use assets - MPC | 229 | 231 | |||||||||
| Long-term lease receivables - MPC | 854 | 386 | |||||||||
| Unguaranteed residual asset - MPC | 47 | 23 | |||||||||
| Total | 1,161 | 672 | |||||||||
| Current liabilities - related parties | |||||||||||
Payables - MPC(1) | 1,657 | 215 | |||||||||
| Payables - Other | 45 | 43 | |||||||||
| Operating lease liabilities - MPC | 1 | 1 | |||||||||
| Deferred revenue - Minimum volume deficiencies - MPC | 35 | 66 | |||||||||
| Deferred revenue - Project reimbursements - MPC | 41 | 30 | |||||||||
| Deferred revenue - Project reimbursements - Other | 1 | 1 | |||||||||
| Total | 1,780 | 356 | |||||||||
| Long-term liabilities - related parties | |||||||||||
| Long-term operating lease liabilities - MPC | 228 | 229 | |||||||||
| Long-term deferred revenue - Project reimbursements - MPC | 68 | 47 | |||||||||
| Long-term deferred revenue - Project reimbursements - Other | 6 | 7 | |||||||||
| Total | $ | 302 | $ | 283 | |||||||
(1) Includes $1,450 million as of the year ended December 31, 2021 related to outstanding borrowings on the intercompany loan with MPC.
7. Equity
Units Outstanding
MPLX had 1,016,178,378 common units outstanding as of December 31, 2021. Of that number, 647,415,452 were owned by MPC, which also owns the non-economic GP Interest as described below. MPLX had 600,000 Series B preferred units outstanding as of December 31, 2021. The sections below describe activities and events which impacted our unit balances throughout the three years ended December 31, 2021.
Unit Repurchase Program
On November 2, 2020, MPLX announced the board authorization of a unit repurchase program for the repurchase of up to $1 billion of MPLX’s outstanding common units held by the public. MPLX may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, tender offers, accelerated unit repurchases or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of repurchases will depend upon several factors, including market and business conditions, and repurchases may be initiated, suspended or discontinued at any time. The repurchase
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authorization has no expiration date. The table below summarizes the repurchases made under the unit repurchase program for the years ended December 31, 2021 and 2020:
| 2021 | 2020 | ||||||||||
| Number of units repurchased | 22,907,174 | 1,473,843 | |||||||||
Cash paid for units repurchased (in millions) | $ | 630 | $ | 33 | |||||||
| Average cost per unit | $ | 27.52 | $ | 22.29 | |||||||
As of December 31, 2021 we had $337 million remaining available under the program for future repurchases.
Wholesale Exchange and Merger
In connection with the Wholesale Exchange as discussed in Note 4, MPLX redeemed 18,582,088 units from MPC in exchange for all of the outstanding membership interests in WRW. These units were cancelled by MPLX immediately following the transaction.
In connection with the Merger and as discussed in Note 4, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units while ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. This resulted in the issuance of MPLX common units of approximately 102 million units to public unitholders and approximately 161 million units to MPC in connection with MPLX's acquisition of ANDX on July 30, 2019.
Series A Redeemable Preferred Unit Conversions - Since 2019, certain Series A preferred unitholders have exercised their rights to convert their Series A preferred units into approximately 1.2 million common units as discussed in Note 9.
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The table below summarizes the changes in the number of units outstanding for the years ended December 31, 2019, 2020, and 2021:
| (In units) | Total Common Units | ||||
| Balance at December 31, 2018 | 794,089,518 | ||||
| Unit-based compensation awards | 288,031 | ||||
| Issuance of units in connection with the Merger (See Note 4) | 262,829,592 | ||||
| Conversion of Series A preferred units | 1,148,330 | ||||
| Balance at December 31, 2019 | 1,058,355,471 | ||||
| Unit-based compensation awards | 478,438 | ||||
| Wholesale Exchange | (18,582,088) | ||||
| Units redeemed in unit repurchase program | (1,473,843) | ||||
| Balance at December 31, 2020 | 1,038,777,978 | ||||
| Unit-based compensation awards | 214,466 | ||||
| Conversion of Series A preferred units | 93,108 | ||||
| Units redeemed in unit repurchase program | (22,907,174) | ||||
| Balance at December 31, 2021 | 1,016,178,378 | ||||
Series B Preferred Units - Prior to the Merger, ANDX issued 600,000 units of 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests of ANDX at a price to the public of $1,000 per unit. Upon completion of the Merger, the ANDX preferred units converted to preferred units of MPLX representing substantially equivalent limited partnership interests in MPLX. The Series B preferred units are pari passu with the Series A preferred units with respect to distribution rights and rights upon liquidation.
MPLX has the right to redeem some or all of the Series B preferred units, at any time, on or after February 15, 2023. MPLX will pay unitholders the Series B preferred unit redemption price of $1,000 per unit plus any accumulated and unpaid distributions up to the redemption date.
Distributions on the Series B preferred units are payable semi-annually in arrears on the 15th day, or the first business day thereafter, of February and August of each year 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.
The changes in the Series B preferred unit balance for 2021 and 2020 are included in the Consolidated Balance Sheets and Consolidated Statements of Equity within “Equity of Predecessor” for the period prior to the Merger and within “Series B preferred units” for the period following the Merger. The Series B preferred units were recorded at fair value as of July 30, 2019.
Issuance of Additional Securities – The Sixth Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 1, 2021 (“Partnership Agreement”), authorizes MPLX to issue an unlimited number of additional securities for the consideration and on the terms and conditions determined by the general partner without the approval of the unitholders.
Net Income Allocation – In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to Series A and Series B preferred unitholders first and subsequently allocated to the limited partner unitholders in accordance with their respective ownership percentages.
Cash Distributions – The Partnership Agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders and preferred unitholders will receive. On January 25, 2022, MPLX declared a quarterly cash distribution, based on the results of the fourth quarter of 2021, totaling $715 million, or $0.7050 per common unit. This rate was also received by Series A preferred unitholders. These distributions were paid on February 14, 2022 to unitholders of record on February 4, 2022.
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Total distributions for the twelve months ended December 31, 2021, 2020 and 2019 are summarized in the table below. The 2021 period includes a special distribution amount of $0.575 per common unit (the “Special Distribution Amount”) related to the distribution declared for the third quarter of 2021, which was paid during the fourth quarter of 2021.
| 2021 | 2020 | 2019 | |||||||||||||||
| Distributions per common unit | $ | 3.36 | $ | 2.75 | $ | 2.69 | |||||||||||
Additionally, in accordance with the distribution rights discussed above, MPLX made a cash distribution to holders of the Series B preferred unitholders on February 15, 2022 of approximately $21 million.
The allocation of total quarterly cash distributions to general, limited, and preferred unitholders is as follows for the years ended December 31, 2021, 2020 and 2019. MPLX’s distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.
| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
| Limited partners' distributions: | |||||||||||||||||
Common unitholders, includes common units of general partner (1) | $ | 3,432 | $ | 2,872 | $ | 2,635 | |||||||||||
Series A preferred unit distributions (1) | 100 | 81 | 81 | ||||||||||||||
| Series B preferred unit distribution | 41 | 41 | 42 | ||||||||||||||
| Total cash distributions declared | $ | 3,573 | $ | 2,994 | $ | 2,758 | |||||||||||
(1) 2021 period includes the Special Distribution Amount.
The distribution on common units for the year ended December 31, 2019 includes the impact of the issuance of approximately 102 million units issued to public unitholders and approximately 161 million units issued to MPC in connection with the Merger. Due to the timing of the closing, distributions presented in the table above include second quarter distributions on MPLX common units issued to former ANDX unitholders in connection with the Merger. The distributions on common units exclude $37.5 million of waived distributions for the year ended December 31, 2019. This waiver was instituted in 2017 under the terms of ANDX’s historical partnership agreement with Andeavor. The waiver is no longer applicable after 2019 based on the original term in the waiver agreement. Also included in the table above is $21 million of distributions earned by the Series B preferred units for 2019 as well as $21 million of distributions earned on the Series B units prior to the Merger and declared and paid by MPLX during the third quarter of 2019.
8. Net Income/(Loss) Per Limited Partner Unit
Net income/(loss) per unit applicable to common limited partner units is computed by dividing net income/(loss) attributable to MPLX LP less income/(loss) allocated to participating securities by the weighted average number of common units outstanding. Classes of participating securities include common units, equity-based compensation awards, Series A preferred units and Series B preferred units. Additional MPLX common units and MPLX Series B preferred units were issued on July 30, 2019 as a result of the Merger as discussed in Note 4. Distributions declared on these newly issued common and Series B preferred units are a reduction to income available to MPLX common unit holders due to their participation in distributions of income.
The Merger was a transfer between entities under common control as discussed in Note 4. As entities under common control with MPC, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings have been allocated to the general partner and do not affect the net income/(loss) per unit calculation. The earnings for the entities acquired under common control will be included in the net income/(loss) per unit calculation prospectively as described above.
In 2021, 2020 and 2019, MPLX had dilutive potential common units consisting of certain equity-based compensation awards. Anti-dilutive potential common units omitted from the diluted earnings per unit calculation for the years ended December 31, 2021, 2020 and 2019 were less than 1 million.
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| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
| Net income/(loss) attributable to MPLX LP | $ | 3,077 | $ | (720) | $ | 1,033 | |||||||||||
Less: Distributions declared on Series A preferred units(1) | 100 | 81 | 81 | ||||||||||||||
| Distributions declared on Series B preferred units | 41 | 41 | 42 | ||||||||||||||
Limited partners’ distributions declared on MPLX common units (including common units of general partner)(1)(2) | 3,432 | 2,872 | 2,635 | ||||||||||||||
| Undistributed net loss attributable to MPLX LP | $ | (496) | $ | (3,714) | $ | (1,725) | |||||||||||
(1)The year ended December 31, 2021 includes the Special Distribution Amount.
(2)Distributions on common units exclude $37.5 million of waived distributions for the year ended December 31, 2019, with respect to units held by MPC and its affiliates.
| 2021 | ||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | ||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit: | ||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | ||||||||||||||||||||||||||
| Distributions declared | $ | 3,432 | $ | 100 | $ | 41 | $ | 3,573 | ||||||||||||||||||
| Undistributed net loss attributable to MPLX LP | (496) | — | — | (496) | ||||||||||||||||||||||
| Net income attributable to MPLX LP | $ | 2,936 | $ | 100 | $ | 41 | $ | 3,077 | ||||||||||||||||||
| Weighted average units outstanding: | ||||||||||||||||||||||||||
| Basic | 1,027 | 1,027 | ||||||||||||||||||||||||
| Diluted | 1,027 | 1,027 | ||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | ||||||||||||||||||||||||||
| Basic | $ | 2.86 | ||||||||||||||||||||||||
| Diluted | $ | 2.86 | ||||||||||||||||||||||||
| 2020 | ||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | ||||||||||||||||||||||
| Basic and diluted net (loss)/income attributable to MPLX LP per unit: | ||||||||||||||||||||||||||
| Net (loss)/income attributable to MPLX LP: | ||||||||||||||||||||||||||
| Distributions declared | $ | 2,872 | $ | 81 | $ | 41 | $ | 2,994 | ||||||||||||||||||
| Undistributed net loss attributable to MPLX LP | (3,714) | — | — | (3,714) | ||||||||||||||||||||||
| Net (loss)/income attributable to MPLX LP | $ | (842) | $ | 81 | $ | 41 | $ | (720) | ||||||||||||||||||
| Weighted average units outstanding: | ||||||||||||||||||||||||||
| Basic | 1,051 | 1,051 | ||||||||||||||||||||||||
| Diluted | 1,051 | 1,051 | ||||||||||||||||||||||||
| Net loss attributable to MPLX LP per limited partner unit: | ||||||||||||||||||||||||||
| Basic | $ | (0.80) | ||||||||||||||||||||||||
| Diluted | $ | (0.80) | ||||||||||||||||||||||||
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| 2019 | ||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | ||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit: | ||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | ||||||||||||||||||||||||||
| Distribution declared | $ | 2,635 | $ | 81 | $ | 42 | $ | 2,758 | ||||||||||||||||||
| Undistributed net loss attributable to MPLX LP | (1,725) | — | — | (1,725) | ||||||||||||||||||||||
| Net income attributable to MPLX LP | $ | 910 | $ | 81 | $ | 42 | $ | 1,033 | ||||||||||||||||||
| Weighted average units outstanding: | ||||||||||||||||||||||||||
| Basic | 906 | 906 | ||||||||||||||||||||||||
| Diluted | 907 | 907 | ||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | ||||||||||||||||||||||||||
| Basic | $ | 1.00 | ||||||||||||||||||||||||
| Diluted | $ | 1.00 | ||||||||||||||||||||||||
9. Series A Preferred Units
Private Placement of Preferred Units – On May 13, 2016, MPLX completed the private placement of approximately 30.8 million 6.5 percent Series A Convertible preferred units for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the sale of the Series A preferred units were used for capital expenditures, repayment of debt and general business purposes.
Preferred Unit Distribution Rights - The Series A preferred units rank senior to all common units and pari passu with all Series B preferred units with respect to distributions and rights upon liquidation. The holders of the Series A preferred units are entitled to receive, when and if declared by the board, 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, including any special distributions made to common unitholders. On January 25, 2022, MPLX declared a quarterly cash distribution of $0.7050 per common unit for the fourth quarter of 2021. Holders of the Series A preferred units received the common unit rate in lieu of the lower $0.528125 base amount.
The holders may convert their Series A preferred units into common units at any time, in full or in part, subject to minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, MPLX may convert the Series A preferred units into common units at any time, in whole or in part, subject to certain minimum conversion amounts and conditions, if the closing price of MPLX common units is greater than $48.75 for the 20-day trading period immediately preceding the conversion notice date. The conversion rate for the Series A preferred units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions on the applicable preferred unit, divided by (b) $32.50, subject to adjustment for unit distributions, unit splits and similar transactions. The holders of the Series A preferred units are entitled to vote on an as-converted basis with the common unitholders and have certain other class voting rights with respect to any amendment to the MPLX partnership agreement that would adversely affect any rights, preferences or privileges of the preferred units. In addition, upon certain events involving a change of control, the holders of preferred units may elect, among other potential elections, to convert their Series A preferred units to common units at the then applicable change of control conversion rate.
Preferred Units Outstanding - During 2019 and 2021, certain holders exercised their right to convert a total of 1.15 million and 0.1 million Series A preferred units into common units, respectively. As a result of these transactions, approximately 29.5 million Series A preferred units remain outstanding as of December 31, 2021. For detailed information regarding the conversion of Series A preferred units to common units see Note 7.
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Financial Statement Presentation - The Series A preferred units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event, which is outside MPLX’s control. Therefore, they are presented as temporary equity in the mezzanine section of the Consolidated Balance Sheets. The Series A preferred units have been recorded at their issuance date fair value, net of issuance costs. Income allocations increase the carrying value and declared distributions decrease the carrying value of the Series A preferred units. As the Series A preferred units are not currently redeemable and not probable of becoming redeemable, adjustment to the initial carrying amount is not necessary and would only be required if it becomes probable that the Series A preferred units would become redeemable.
For a summary of changes in the redeemable preferred balance for 2021, 2020 and 2019, see the Consolidated Statements of Equity.
10. Segment Information
MPLX’s chief operating decision maker is the chief executive officer (“CEO”) of its general partner. The CEO reviews MPLX’s discrete financial information, makes operating decisions, assesses financial performance and allocates resources on a type of service basis. MPLX has two reportable segments: L&S and G&P. Each of these segments is organized and managed based upon the nature of the products and services it offers.
•L&S – transports, gathers, stores and distributes crude oil, refined products, and other hydrocarbon-based products. Also includes the operation of refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns.
•G&P – gathers, processes and transports natural gas; and gathers, transports, fractionates, stores and markets NGLs.
Our CEO evaluates the performance of our segments using Segment Adjusted EBITDA. Amounts included in net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) provision/(benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) gain/(loss) on extinguishment of debt; (v) non-cash equity-based compensation; (vi) impairment expense; (vii) net interest and other financial costs; (viii) income/(loss) from equity method investments; (ix) distributions and adjustments related to equity method investments; (x) unrealized derivative gains/(losses); (xi) acquisition costs; (xii) noncontrolling interests; and (xiii) other adjustments as deemed necessary. These items are either: (i) believed to be non-recurring in nature; (ii) not believed to be allocable or controlled by the segment; or (iii) are not tied to the operational performance of the segment.
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The tables below present information about revenues and other income, Segment Adjusted EBITDA, restructuring expenses, capital expenditures and investments in unconsolidated affiliates as well as total assets for our reportable segments:
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| L&S | ||||||||||||||||||||
| Service revenue | $ | 3,918 | $ | 3,889 | $ | 3,765 | ||||||||||||||
| Rental income | 772 | 985 | 1,235 | |||||||||||||||||
| Sales-type lease revenue | 435 | 152 | 7 | |||||||||||||||||
| Product related revenue | 14 | 51 | 91 | |||||||||||||||||
| Income from equity method investments | 153 | 154 | 200 | |||||||||||||||||
| Other income | 61 | 54 | 54 | |||||||||||||||||
Total segment revenues and other income(1) | 5,353 | 5,285 | 5,352 | |||||||||||||||||
Segment Adjusted EBITDA(2) | 3,681 | 3,488 | 2,748 | |||||||||||||||||
| Restructuring expenses | — | 29 | — | |||||||||||||||||
Capital expenditures(3) | 316 | 498 | 1,060 | |||||||||||||||||
| Investments in unconsolidated affiliates | 33 | 141 | 289 | |||||||||||||||||
| G&P | ||||||||||||||||||||
| Service revenue | 2,023 | 2,088 | 2,188 | |||||||||||||||||
| Rental income | 347 | 365 | 349 | |||||||||||||||||
| Product related revenue | 2,066 | 868 | 997 | |||||||||||||||||
| Income/(loss) from equity method investments | 168 | (1,090) | 90 | |||||||||||||||||
| Other income | 70 | 53 | 65 | |||||||||||||||||
Total segment revenues and other income(1) | 4,674 | 2,284 | 3,689 | |||||||||||||||||
Segment Adjusted EBITDA(2) | 1,879 | 1,723 | 1,586 | |||||||||||||||||
| Restructuring expenses | — | 8 | — | |||||||||||||||||
Capital expenditures(3) | 224 | 441 | 1,203 | |||||||||||||||||
| Investments in unconsolidated affiliates | $ | 118 | $ | 125 | $ | 424 | ||||||||||||||
(1) Within the total segment revenues and other income amounts presented above, third party revenues for the L&S segment were $503 million, $567 million and $660 million for 2021, 2020 and 2019, respectively. Third party revenues for the G&P segment were $4,463 million, $2,088 million and $3,474 million for 2021, 2020 and 2019, respectively.
(2) See below for the reconciliation from Segment Adjusted EBITDA to “Net income/(loss).”
(3) Capital expenditures do not include adjustments for asset retirement expenditures.
| December 31, | ||||||||||||||
| (In millions) | 2021 | 2020 | ||||||||||||
| Segment assets | ||||||||||||||
| Cash and cash equivalents | $ | 13 | $ | 15 | ||||||||||
| L&S | 20,655 | 20,938 | ||||||||||||
| G&P | 14,839 | 15,461 | ||||||||||||
| Total assets | $ | 35,507 | $ | 36,414 | ||||||||||
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The table below provides a reconciliation between “Net income” and Segment Adjusted EBITDA.
| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
| Reconciliation to Net income/(loss): | |||||||||||||||||
| L&S Segment Adjusted EBITDA | $ | 3,681 | $ | 3,488 | $ | 2,748 | |||||||||||
| G&P Segment Adjusted EBITDA | 1,879 | 1,723 | 1,586 | ||||||||||||||
| Total reportable segments | 5,560 | 5,211 | 4,334 | ||||||||||||||
Depreciation and amortization(1) | (1,287) | (1,377) | (1,254) | ||||||||||||||
| Provision for income taxes | (1) | (2) | — | ||||||||||||||
| Amortization of deferred financing costs | (70) | (61) | (42) | ||||||||||||||
| Gain on extinguishment of debt | 10 | 19 | — | ||||||||||||||
| Non-cash equity-based compensation | (9) | (14) | (22) | ||||||||||||||
| Impairment expense | (42) | (2,165) | (1,197) | ||||||||||||||
| Net interest and other financial costs | (819) | (854) | (873) | ||||||||||||||
| Income/(loss) from equity method investments | 321 | (936) | 290 | ||||||||||||||
| Distributions/adjustments related to equity method investments | (537) | (499) | (562) | ||||||||||||||
Unrealized derivative (losses)/gains(2) | (45) | (3) | 1 | ||||||||||||||
| Acquisition costs | — | — | (14) | ||||||||||||||
| Restructuring expenses | — | (37) | — | ||||||||||||||
| Other | (8) | (6) | (1) | ||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | 39 | 37 | 32 | ||||||||||||||
Adjusted EBITDA attributable to Predecessor(3) | — | — | 770 | ||||||||||||||
| Net income/(loss) | $ | 3,112 | $ | (687) | $ | 1,462 | |||||||||||
(1) Depreciation and amortization attributable to L&S was $546 million, $633 million and $503 million for the years ended 2021, 2020 and 2019, respectively. Depreciation and amortization attributable to G&P was $741 million, $744 million and $751 million for 2021, 2020 and 2019, respectively.
(2) MPLX makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.
(3) The Adjusted EBITDA adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP prior to the acquisition date.
11. Major Customers and Concentration of Credit Risk
The table below shows, by segment, the percentage of operating revenues as well as total revenues and other income with MPC which is our most significant customer and our largest concentration of credit risk.
| 2021 | 2020 | 2019 | |||||||||||||||
Total revenues and other income(1) | |||||||||||||||||
| L&S | 90 | % | 89 | % | 88 | % | |||||||||||
| G&P | 3 | % | 4 | % | 4 | % | |||||||||||
| Total | 50 | % | 55 | % | 53 | % | |||||||||||
(1) The percent calculations exclude losses attributable to the impairment of equity method investments.
MPLX has a concentration of trade receivables due from customers in the same industry: MPC, integrated oil companies, natural gas exploration and production companies, independent refining companies and other pipeline companies. These concentrations of customers may impact MPLX’s overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. MPLX manages its exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures; and for certain transactions, it may request letters of credit, prepayments or guarantees.
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12. Inventories
Inventories consist of the following:
| December 31, | ||||||||||||||
| (In millions) | 2021 | 2020 | ||||||||||||
| NGLs | $ | 12 | $ | 5 | ||||||||||
| Line fill | 23 | 13 | ||||||||||||
| Spare parts, materials and supplies | 107 | 100 | ||||||||||||
| Total inventories | $ | 142 | $ | 118 | ||||||||||
13. Property, Plant and Equipment
Property, plant and equipment with associated accumulated depreciation is shown below:
| Estimated Useful Lives | December 31, | |||||||||||||||||||
| (In millions) | 2021 | 2020 | ||||||||||||||||||
| L&S | ||||||||||||||||||||
| Pipelines | 3-50 years | $ | 6,299 | $ | 6,026 | |||||||||||||||
| Refining logistics | 13-40 years | 1,650 | 2,333 | |||||||||||||||||
| Terminals | 4-40 years | 1,655 | 1,643 | |||||||||||||||||
| Marine | 15-20 years | 965 | 965 | |||||||||||||||||
| Land, building and other | 2-60 years | 1,589 | 1,584 | |||||||||||||||||
| Construction-in-progress | 213 | 262 | ||||||||||||||||||
| Total L&S property, plant and equipment | 12,371 | 12,813 | ||||||||||||||||||
| G&P | ||||||||||||||||||||
| Gathering and transportation | 5-40 years | 7,668 | 7,547 | |||||||||||||||||
| Processing and fractionation | 10-40 years | 5,795 | 5,721 | |||||||||||||||||
| Land, building and other | 3-40 years | 514 | 507 | |||||||||||||||||
| Construction-in-progress | 198 | 287 | ||||||||||||||||||
| Total G&P property, plant and equipment | 14,175 | 14,062 | ||||||||||||||||||
| Total property, plant and equipment | 26,546 | 26,875 | ||||||||||||||||||
Less accumulated depreciation(1) | 6,504 | 5,657 | ||||||||||||||||||
| Property, plant and equipment, net | $ | 20,042 | $ | 21,218 | ||||||||||||||||
(1) Includes property, plant and equipment impairment charges recorded during the respective period, as discussed below.
Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable based on the expected undiscounted future cash flow of an asset group. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which is at least at the segment level and in some cases for similar assets in the same geographic region where cash flows can be separately identified. If the sum of the undiscounted cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than the calculated fair value.
In the second quarter of 2021, we recognized impairment expense of $42 million within our G&P segment related to our continued emphasis on portfolio optimization with the divestiture of several non-core assets and the closure of other non-core assets.
During the first quarter of 2020, we identified an impairment trigger relating to asset groups within our Western G&P reporting unit as a result of significant impacts to forecasted cash flows for these asset groups resulting from the deterioration in the economy and the environment in which MPLX and its customers operate, as well as a sustained decrease in unit price. The cash flows associated with these assets were significantly impacted by volume declines reflecting decreased forecasted producer customer production as a result of lower commodity prices. After assessing each asset group within the Western G&P reporting unit for impairment, only the East Texas G&P asset
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group resulted in the fair value of the underlying assets being less than the carrying value. As a result, an impairment of $174 million was recorded to “Impairment expense” on the Consolidated Statements of Income. Fair value of the assets was determined using a combination of an income and cost approach. The income approach utilized significant assumptions including management’s best estimates of the expected future cash flows, the estimated useful life of the asset group and discount rate. The cost approach utilized assumptions for the current replacement costs of similar assets adjusted for estimated depreciation and deterioration of the existing equipment and economic obsolescence. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of our impairment analysis will prove to be an accurate prediction of the future. The fair value measurements for the asset group fair values represent Level 3 measurements.
14. Goodwill and Intangibles
Goodwill
MPLX annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount.
Our reporting units are one level below our operating segments and are determined based on the way in which segment management operates and reviews each operating segment. We have five reporting units, three of which have goodwill allocated to them. For the annual impairment assessment as of November 30, 2021, management performed only a qualitative assessment for one reporting unit as we determined it was more likely than not that the fair value of the reporting unit exceeded the carrying value. The fair value of the two remaining reporting units for which a quantitative assessment was performed was determined based on applying both a discounted cash flow, or income approach, as well as a market approach which resulted in the fair value of the reporting units exceeding their carrying value by 23 percent and 51 percent. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method included management’s best estimates of the discount rate of 7.2 percent as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact future volumes and capital requirements. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be an accurate prediction of the future. The fair value measurements for the individual reporting units represent Level 3 measurements. Total goodwill at December 31, 2021 was $7.7 billion and no impairment was recorded as a result of our November 30, 2021 annual goodwill impairment analysis.
During the first quarter of 2020, we determined that an interim impairment analysis of the goodwill recorded was necessary based on consideration of a number of first quarter events and circumstances. Our producer customers in our Eastern G&P region reduced production forecasts and drilling activity in response to the global economic downturn. Additionally, a decline in NGL prices impacted our future revenue forecast. After performing our evaluations related to the interim impairment of goodwill during the first quarter of 2020, we recorded an impairment of $1,814 million within the Eastern G&P reporting unit, which was recorded to “Impairment expense” on the Consolidated Statements of Income. The impairment was primarily driven by additional guidance related to the slowing of drilling activity, which reduced production growth forecasts from our producer customers. The interim impairment assessment of the remaining reporting units with goodwill resulted in the fair value of the reporting units exceeding their carrying value. The fair value of our reporting units was determined based on applying both a discounted cash flow or income approach as well as a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method included management’s best estimates of the discount rate, which ranged from 9.5 percent to 11.5 percent, as well as estimates of future cash flows, which are impacted primarily by producer customers’ development plans, which impact future volumes and capital requirements.
After performing our evaluations related to the impairment of goodwill during the fiscal year ended December 31, 2019, we recorded an impairment of $1,197 million within the Western G&P reporting unit. The fair value of the remaining reporting units’ were in excess of their carrying values. The impairment was primarily driven by updated guidance related to the slowing of drilling activity, which has reduced production growth forecasts from our producer customers.
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The changes in carrying amount of goodwill were as follows for the periods presented:
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Gross goodwill as of December 31, 2019 | $ | 7,722 | $ | 3,141 | $ | 10,863 | |||||||||||
| Accumulated impairment losses | — | (1,327) | (1,327) | ||||||||||||||
| Balance as of December 31, 2019 | 7,722 | 1,814 | 9,536 | ||||||||||||||
| Impairment losses | — | (1,814) | (1,814) | ||||||||||||||
Wholesale Exchange (Note 4) | (65) | — | (65) | ||||||||||||||
| Balance as of December 31, 2020 | 7,657 | — | 7,657 | ||||||||||||||
| Impairment losses | — | — | — | ||||||||||||||
| Balance as of December 31, 2021 | 7,657 | — | 7,657 | ||||||||||||||
| Gross goodwill as of December 31, 2021 | 7,657 | 3,141 | 10,798 | ||||||||||||||
| Accumulated impairment losses | — | (3,141) | (3,141) | ||||||||||||||
| Balance as of December 31, 2021 | $ | 7,657 | $ | — | $ | 7,657 | |||||||||||
Intangible Assets
MPLX’s intangible assets are comprised of customer contracts and relationships. Gross intangible assets with accumulated amortization as of December 31, 2021 and 2020 is shown below:
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||||||||||||||||||||
| (In millions) | Useful Life | Gross | Accumulated Amortization(1) | Net | Gross | Accumulated Amortization(1)(2) | Net | ||||||||||||||||||||||||||||||||||
| L&S | 6 - 8 years | $ | 283 | $ | (117) | $ | 166 | $ | 283 | $ | (81) | $ | 202 | ||||||||||||||||||||||||||||
| G&P | 6 - 25 years | 1,288 | (623) | 665 | 1,288 | (531) | 757 | ||||||||||||||||||||||||||||||||||
| $ | 1,571 | $ | (740) | $ | 831 | $ | 1,571 | $ | (612) | $ | 959 | ||||||||||||||||||||||||||||||
(1) Amortization expense attributable to the G&P segment for the years ended December 31, 2021 and 2020 was $92 million and $98 million, respectively. Amortization expense attributable to the L&S segment for both years ended December 31, 2021 and 2020 was $36 million.
(2) Impairment charge of $177 million is included within the G&P accumulated amortization for the year ended December 31, 2020.
During the first quarter of 2020, we also determined that an impairment analysis of intangibles within our Western G&P reporting unit was necessary. See Note 13 for additional information regarding our assessment around the Western G&P reporting unit, and more specifically our East Texas G&P asset group. The fair value of the intangibles in our East Texas G&P asset group were determined based on applying the multi-period excess earnings method, which is an income approach. Key assumptions included management’s best estimates of the expected future cash flows from existing customers, customer attrition rates and the discount rate. After performing our evaluations related to the impairment of intangible assets associated with our East Texas G&P asset group during the first quarter of 2020, we recorded an impairment of $177 million to “Impairment expense” on the Consolidated Statements of Income related to our customer relationships.
Estimated future amortization expense related to the intangible assets at December 31, 2021 is as follows:
| (In millions) | ||||||||
| 2022 | $ | 127 | ||||||
| 2023 | 127 | |||||||
| 2024 | 127 | |||||||
| 2025 | 113 | |||||||
| 2026 | 104 | |||||||
| Thereafter | 233 | |||||||
| Total | $ | 831 | ||||||
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15. Fair Value Measurements
Fair Values – Recurring
Fair value measurements and disclosures relate primarily to MPLX’s derivative positions as discussed in Note 16. The following table presents the financial instruments carried at fair value on a recurring basis as of December 31, 2021 and 2020 by fair value hierarchy level. MPLX has elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty.
| December 31, | |||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||
| (In millions) | Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||
| Significant unobservable inputs (Level 3) | |||||||||||||||||||||||
| Embedded derivatives in commodity contracts | $ | — | $ | (108) | $ | — | $ | (63) | |||||||||||||||
| Total carrying value on Consolidated Balance Sheets | $ | — | $ | (108) | $ | — | $ | (63) | |||||||||||||||
Level 3 instruments include an embedded derivative in commodity contracts. The embedded derivative liability relates to a natural gas purchase commitment embedded in a keep-whole processing agreement. The fair value calculation for these Level 3 instruments used significant unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging from $0.72 to $1.79 per gallon with a weighted average of $0.92 per gallon and (2) the probability of renewal of 100 percent for the -year renewal term of the gas purchase commitment and related keep-whole processing agreement. Increases or decreases in the fractionation spread result in an increase or decrease in the fair value of the embedded derivative liability, respectively. Beyond the embedded derivative discussed above, we had no outstanding commodity derivative contracts as of December 31, 2021 or December 31, 2020.
Changes in Level 3 Fair Value Measurements
The following table is a reconciliation of the net beginning and ending balances recorded for net assets and liabilities classified as Level 3 in the fair value hierarchy.
| 2021 | 2020 | ||||||||||
| (In millions) | Embedded Derivatives in Commodity Contracts (net) | Embedded Derivatives in Commodity Contracts (net) | |||||||||
| Fair value at beginning of period | $ | (63) | $ | (60) | |||||||
Total losses (realized and unrealized) included in earnings(1) | (59) | (9) | |||||||||
| Settlements | 14 | 6 | |||||||||
| Fair value at end of period | (108) | (63) | |||||||||
| The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to liabilities still held at end of period | $ | (47) | $ | (4) | |||||||
(1) Losses on derivatives embedded in commodity contracts are recorded in “Purchased product costs” on the Consolidated Statements of Income.
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Fair Values – Reported
MPLX’s primary financial instruments are cash and cash equivalents, receivables, receivables from related parties, lease receivables from related parties, accounts payable, payables to related parties and debt. MPLX’s fair value assessment incorporates a variety of considerations, including (1) the duration of the instruments, (2) MPC’s investment-grade credit rating and (3) the historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. MPLX believes the carrying values of its current assets and liabilities approximate fair value. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximates fair value due to the variable interest rate that approximate current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 16).
The fair value of MPLX’s debt is estimated based on recent market non-binding indicative quotes. The debt fair values are considered Level 3 measurements. The following table summarizes the fair value and carrying value of our third-party debt, excluding finance leases:
| December 31, | |||||||||||||||||||||||
| 2021 | 2020 | ||||||||||||||||||||||
| (In millions) | Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||||||||
Outstanding debt(1) | $ | 20,779 | $ | 18,664 | $ | 22,951 | $ | 20,244 | |||||||||||||||
(1) Amounts outstanding under the MPC Loan Agreement are not included in the table above, as the carrying value approximates fair value. This balance is reflected in “Current liabilities - related parties” on the Consolidated Balance Sheets.
16. Derivative Financial Instruments
For the years 2021, 2020 and 2019, MPLX had no commodity contracts beyond the embedded derivative discussed below.
Embedded Derivative - MPLX has a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer customer in the Southern Appalachian region expiring in December 2027. The customer has the unilateral option to extend the agreement for one -year term through December 2032. For accounting purposes, the natural gas purchase commitment and the term extending option has been aggregated into a single compound embedded derivative. The probability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may exist at the time they would elect whether to renew the contract. The changes in fair value of this compound embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through “Purchased product costs” on the Consolidated Statements of Income. For further information regarding the fair value measurement of derivative instruments, see Note 15. See Note 2 for a discussion of derivatives MPLX may use and the reasons for them. As of December 31, 2021 and 2020, the estimated fair value of this contract was a liability of $108 million and $63 million, respectively.
Certain derivative positions are subject to master netting agreements; therefore, MPLX has elected to offset derivative assets and liabilities that are legally permissible to be offset. As of December 31, 2021 and 2020, there
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were no derivative assets or liabilities that were offset on the Consolidated Balance Sheets. The impact of MPLX’s derivative instruments on its Consolidated Balance Sheets is summarized below:
| December 31, | |||||||||||||||||||||||
| (In millions) | 2021 | 2020 | |||||||||||||||||||||
| Derivative contracts not designated as hedging instruments and their balance sheet location | Asset | Liability | Asset | Liability | |||||||||||||||||||
Commodity contracts(1) | |||||||||||||||||||||||
| Other current assets / Other current liabilities | $ | — | $ | (15) | $ | — | $ | (7) | |||||||||||||||
| Other noncurrent assets / Deferred credits and other liabilities | — | (93) | — | (56) | |||||||||||||||||||
| Total | $ | — | $ | (108) | $ | — | $ | (63) | |||||||||||||||
(1) Includes the embedded derivative in the commodity contract discussed above.
The impact of MPLX’s derivative contracts not designated as hedging instruments and the location of gains and losses recognized on the Consolidated Statements of Income is summarized below:
| (In millions) | 2021 | 2020 | 2019 | ||||||||||||||
| Purchased product costs | |||||||||||||||||
| Realized loss | $ | (14) | $ | (6) | $ | (6) | |||||||||||
| Unrealized (loss)/gain | (45) | (3) | 1 | ||||||||||||||
| Purchased product cost derivative loss | $ | (59) | $ | (9) | $ | (5) | |||||||||||
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17. Debt
MPLX’s outstanding borrowings at December 31, 2021 and 2020 consisted of the following:
| December 31, | |||||||||||
| (In millions) | 2021 | 2020 | |||||||||
| MPLX LP: | |||||||||||
Bank revolving credit facility due July 30, 2024 | $ | 300 | $ | 175 | |||||||
Floating rate senior notes due September 9, 2022 | — | 1,000 | |||||||||
3.500% senior notes due December 1, 2022 | 486 | 486 | |||||||||
3.375% senior notes due March 15, 2023 | 500 | 500 | |||||||||
4.500% senior notes due July 15, 2023 | 989 | 989 | |||||||||
4.875% senior notes due December 1, 2024 | 1,149 | 1,149 | |||||||||
5.250% senior notes due January 15, 2025 | — | 708 | |||||||||
4.000% senior notes due February 15, 2025 | 500 | 500 | |||||||||
4.875% senior notes due June 1, 2025 | 1,189 | 1,189 | |||||||||
1.750% senior notes due March 1, 2026 | 1,500 | 1,500 | |||||||||
4.125% senior notes due March 1, 2027 | 1,250 | 1,250 | |||||||||
4.250% senior notes due December 1, 2027 | 732 | 732 | |||||||||
4.000% senior notes due March 15, 2028 | 1,250 | 1,250 | |||||||||
4.800% senior notes due February 15, 2029 | 750 | 750 | |||||||||
2.650% senior notes due August 15, 2030 | 1,500 | 1,500 | |||||||||
4.500% senior notes due April 15, 2038 | 1,750 | 1,750 | |||||||||
5.200% senior notes due March 1, 2047 | 1,000 | 1,000 | |||||||||
5.200% senior notes due December 1, 2047 | 487 | 487 | |||||||||
4.700% senior notes due April 15, 2048 | 1,500 | 1,500 | |||||||||
5.500% senior notes due February 15, 2049 | 1,500 | 1,500 | |||||||||
4.900% senior notes due April 15, 2058 | 500 | 500 | |||||||||
| Consolidated subsidiaries: | |||||||||||
MarkWest - 4.500% - 4.875% senior notes, due 2023-2025 | 23 | 23 | |||||||||
ANDX - 3.500% - 5.200% senior notes, due 2022-2047 | 45 | 87 | |||||||||
Financing lease obligations(1) | 9 | 11 | |||||||||
| Total | 18,909 | 20,536 | |||||||||
| Unamortized debt issuance costs | (102) | (116) | |||||||||
| Unamortized discount/premium | (236) | (281) | |||||||||
| Amounts due within one year | (499) | (764) | |||||||||
| Total long-term debt due after one year | $ | 18,072 | $ | 19,375 | |||||||
(1) See Note 20 for lease information.
The following table shows five years of scheduled debt payments, including payments on finance lease obligations:
| (In millions) | |||||
| 2022 | $ | 502 | |||
| 2023 | 1,502 | ||||
| 2024 | 1,451 | ||||
| 2025 | 1,701 | ||||
| 2026 | $ | 1,501 | |||
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Credit Agreements
MPLX Credit Agreement
MPLX has a $3.5 billion revolving credit facility (the “MPLX Credit Agreement”) which is set to mature on July 30, 2024. The MPLX Credit Agreement includes a letter of credit issuing capacity of $300 million and swingline capacity of $150 million.
The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1.0 billion, subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended, for up to two additional one year periods, subject to, among other conditions, the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date. Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on MPLX’s long-term debt.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that MPLX considers to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions and dispositions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX and/or certain of its subsidiaries from incurring debt, creating liens on our assets and entering into transactions with affiliates. As of December 31, 2021, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
During the year ended December 31, 2021, MPLX borrowed $4,175 million under the MPLX Credit Agreement, at a weighted average interest rate of 1.343 percent, and repaid $4,050 million of these borrowings. At December 31, 2021, MPLX had $300 million outstanding borrowings and less than $1 million in letters of credit outstanding under this facility, resulting in total availability of $3,200 million, or approximately 91 percent of the borrowing capacity.
During the year ended December 31, 2020, MPLX borrowed $3,815 million under the MPLX Credit Agreement, at a weighted average interest rate of 1.49 percent, and repaid $3,640 million of these borrowings. At December 31, 2020, MPLX had $175 million outstanding borrowings and less than $1 million in letters of credit outstanding under this facility, resulting in total availability of $3,325 million, or approximately 95 percent of the borrowing capacity.
Term Loan Agreement
On September 26, 2019, MPLX entered into a Term Loan Agreement, which provided for a committed term loan facility for up to an aggregate of $1.0 billion. Borrowings under the Term Loan Agreement bore interest, at MPLX’s election, at either (i) the Adjusted LIBO Rate (as defined in the Term Loan Agreement) plus a margin ranging from 75.0 basis points to 100.0 basis points per annum, depending on MPLX’s credit ratings or (ii) the Alternate Base Rate (as defined in the Term Loan Agreement). On August 18, 2020, MPLX fully repaid the $1.0 billion of outstanding borrowings on the Term Loan Agreement, which resulted in the recognition of $1 million of unamortized issuance costs, which is included on the Consolidated Statements of Income as “Other financial costs.”
Floating Rate Senior Notes
On September 9, 2019, MPLX issued $2.0 billion aggregate principal amount of floating rate senior notes in a public offering, consisting of $1.0 billion aggregate principal amount of notes due September 2021 and $1.0 billion aggregate principal amount of notes due September 2022 (collectively, the “Floating Rate Senior Notes”). The Floating Rate Senior Notes were offered at a price to the public of 100 percent of par. The Floating Rate Senior Notes were callable, in whole or in part, at par plus accrued and unpaid interest at any time on or after September 10, 2020. The net proceeds were used to repay MPLX’s existing indebtedness and/or for general business purposes. Interest on the Floating Rate Senior Notes was payable quarterly in March, June, September and December, commencing on December 9, 2019. The interest rate applicable to the floating rate senior notes due
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September 2021 was LIBOR plus 0.9 percent per annum. The interest rate applicable to the floating rate senior notes due September 2022 was LIBOR plus 1.1 percent per annum.
On September 14, 2020, MPLX redeemed, at par value, all of the $1.0 billion aggregate principal amount of notes due September 2021, which resulted in the recognition of $3 million of unamortized issuance costs, which is included on the Consolidated Statements of Income as “Other financial costs.”
On September 3, 2021 MPLX redeemed, at par value, all of the $1.0 billion aggregate principal amount of floating rate senior notes due September 2022, which resulted in the immediate expense recognition of $2 million of unamortized debt issuance costs. These costs are included on the Consolidated Statements of Income as “Other financial costs.” This redemption was funded primarily by borrowings under the MPC Loan Agreement.
Fixed Rate Senior Notes
Interest on each series of MPLX LP, MarkWest and ANDX senior notes is payable semi-annually in arrears, according to the table below.
| Senior Notes | Interest payable semi-annually in arrears | |||||||
3.500% senior notes due December 1, 2022 | June 1st and December 1st | |||||||
3.375% senior notes due March 15, 2023 | March 15th and September 15th | |||||||
4.500% senior notes due July 15, 2023 | January 15th and July 15th | |||||||
4.875% senior notes due December 1, 2024 | June 1st and December 1st | |||||||
4.000% senior notes due February 15, 2025 | February 15th and August 15th | |||||||
4.875% senior notes due June 1, 2025 | June 1st and December 1st | |||||||
1.750% senior notes due March 1, 2026 | March 1st and September 1st | |||||||
4.125% senior notes due March 1, 2027 | March 1st and September 1st | |||||||
4.250% senior notes due December 1, 2027 | June 1st and December 1st | |||||||
4.000% senior notes due March 15, 2028 | March 15th and September 15th | |||||||
4.800% senior notes due February 15, 2029 | February 15th and August 15th | |||||||
2.650% senior notes due August 15, 2030 | February 15th and August 15th | |||||||
4.500% senior notes due April 15, 2038 | April 15th and October 15th | |||||||
5.200% senior notes due March 1, 2047 | March 1st and September 1st | |||||||
5.200% senior notes due December 1, 2047 | June 1st and December 1st | |||||||
4.700% senior notes due April 15, 2048 | April 15th and October 15th | |||||||
5.500% senior notes due February 15, 2049 | February 15th and August 15th | |||||||
4.900% senior notes due April 15, 2058 | April 15th and October 15th | |||||||
On January 15, 2021 MPLX redeemed all of the $750 million outstanding aggregate principal amount of 5.250 percent senior notes, due January 15, 2025, including approximately $42 million aggregate principal amount of senior notes issued by ANDX, at a price equal to 102.625 percent of the principal amount. The payment of $20 million related to the note premium, offset by the immediate expense recognition of $12 million of unamortized debt premium and issuance costs, resulted in a loss on extinguishment of debt of $8 million that is included on the Consolidated Statements of Income as “Other financial costs.”
On August 18, 2020, MPLX issued $3.0 billion aggregate principal amount of senior notes in a public offering, consisting of $1.5 billion aggregate principal amount of 1.750 percent senior notes due March 2026 and $1.5 billion aggregate principal amount of 2.650 percent senior notes due August 2030 (collectively, the “August 2020 New Senior Notes”). The August 2020 New Senior Notes were offered at a price to the public of 99.785 percent and 99.913 percent of par, respectively. The net proceeds were used to repay the $1.0 billion of outstanding borrowings under the MPLX Term Loan Agreement; to repay the $1.0 billion aggregate principal amount of floating rate notes due September 2021; to redeem all of the $450 million aggregate principal amount of 6.375 percent senior notes due May 2024, $69 million of which was issued by ANDX; and to redeem all of the $300 million aggregate principal amount of 6.250 percent senior notes due October 2022, of which $34 million was issued by ANDX. Proceeds were also used to reduce amounts outstanding under the MPLX Credit Agreement at the time.
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The 6.375 percent senior notes due May 2024 were redeemed at 103.2 percent of the aggregate principal amount, which resulted in a payment of $14 million related to the note premium offset by the immediate recognition of $18 million of unamortized debt premium/discount and issuance costs, both of which are included on the Consolidated Statements of Income as “Other financial costs.” The 6.250 percent senior notes due October 2022 were redeemed at par, and resulted in the immediate recognition of $4 million of unamortized debt premium and issuance costs, which is included on the Consolidated Statements of Income as “Other financial costs.”
18. Revenue
Disaggregation of Revenue
The following tables represent a disaggregation of revenue for each reportable segment for the years ended December 31, 2021, 2020 and 2019:
| 2021 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | 310 | $ | 2,003 | $ | 2,313 | |||||||||||
| Service revenue - related parties | 3,608 | 20 | 3,628 | ||||||||||||||
| Service revenue - product related | — | 345 | 345 | ||||||||||||||
| Product sales | 4 | 1,586 | 1,590 | ||||||||||||||
| Product sales - related parties | 10 | 135 | 145 | ||||||||||||||
| Total revenues from contracts with customers | $ | 3,932 | $ | 4,089 | 8,021 | ||||||||||||
Non-ASC 606 revenue(1) | 2,006 | ||||||||||||||||
| Total revenues and other income | $ | 10,027 | |||||||||||||||
| 2020 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | 333 | $ | 2,064 | $ | 2,397 | |||||||||||
| Service revenue - related parties | 3,556 | 24 | 3,580 | ||||||||||||||
| Service revenue - product related | — | 155 | 155 | ||||||||||||||
| Product sales | 39 | 597 | 636 | ||||||||||||||
| Product sales - related parties | 12 | 116 | 128 | ||||||||||||||
| Total revenues from contracts with customers | $ | 3,940 | $ | 2,956 | 6,896 | ||||||||||||
Non-ASC 606 revenue(1) | 673 | ||||||||||||||||
| Total revenues and other income | $ | 7,569 | |||||||||||||||
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| 2019 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | 346 | $ | 2,152 | $ | 2,498 | |||||||||||
| Service revenue - related parties | 3,419 | 36 | 3,455 | ||||||||||||||
| Service revenue - product related | — | 140 | 140 | ||||||||||||||
| Product sales | 65 | 741 | 806 | ||||||||||||||
| Product sales - related parties | 26 | 116 | 142 | ||||||||||||||
| Total revenues from contracts with customers | $ | 3,856 | $ | 3,185 | 7,041 | ||||||||||||
Non-ASC 606 revenue(1) | 2,000 | ||||||||||||||||
| Total revenues and other income | $ | 9,041 | |||||||||||||||
(1) Non-ASC 606 Revenue includes rental income, sales-type lease revenue, income/(loss) from equity method investments, derivative gains and losses, mark-to-market adjustments, and other income.
Contract Balances
Contract assets typically relate to deficiency payments related to minimum volume commitments and aid in construction agreements where the revenue recognized and MPLX’s rights to consideration for work completed exceeds the amount billed to the customer. Contract assets are included in “Other current assets” and “Other noncurrent assets” on the Consolidated Balance Sheets.
Contract liabilities, which we refer to as “Deferred revenue” and “Long-term deferred revenue,” typically relate to advance payments for aid in construction agreements and deferred customer credits associated with makeup rights and minimum volume commitments. Related to minimum volume commitments, breakage is estimated and recognized into service revenue in instances where it is probable the customer will not use the credit in future periods. We classify contract liabilities as current or long-term based on the timing of when we expect to recognize revenue.
“Receivables, net” primarily relate to our commodity sales. Portions of the “Receivables, net” balance are attributed to the sale of commodity product controlled by MPLX prior to sale while a significant portion of the balance relates to the sale of commodity product on behalf of our producer customers. The sales and related “Receivables, net” are commingled and excluded from the table below. MPLX remits the net sales price back to our producer customers upon completion of the sale. Each period end, certain amounts within accounts payable relate to our payments to producer customers. Such amounts are not deemed material at period end as a result of when we settle with each producer.
The tables below reflect the changes in our contract balances for the years ended December 31, 2021 and 2020:
| (In millions) | Balance at December 31, 2020(1) | Additions/ (Deletions) | Revenue Recognized(2) | Balance at December 31, 2021(1) | |||||||||||||||||||
| Contract assets | $ | 40 | $ | (15) | $ | — | $ | 25 | |||||||||||||||
| Long-term contract assets | 2 | — | — | 2 | |||||||||||||||||||
| Deferred revenue | 37 | 56 | (37) | 56 | |||||||||||||||||||
| Deferred revenue - related parties | 91 | 75 | (106) | 60 | |||||||||||||||||||
| Long-term deferred revenue | 119 | 16 | — | 135 | |||||||||||||||||||
| Long-term deferred revenue - related parties | 48 | (17) | — | 31 | |||||||||||||||||||
| Long-term contract liabilities | $ | 6 | $ | (1) | $ | — | $ | 5 | |||||||||||||||
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| (In millions) | Balance at December 31, 2019(1) | Additions/ (Deletions) | Revenue Recognized(2) | Balance at December 31, 2020(1) | |||||||||||||||||||
| Contract assets | $ | 39 | $ | 3 | $ | (2) | $ | 40 | |||||||||||||||
| Long-term contract assets | — | 2 | — | 2 | |||||||||||||||||||
| Deferred revenue | 23 | 22 | (8) | 37 | |||||||||||||||||||
| Deferred revenue - related parties | 53 | 121 | (83) | 91 | |||||||||||||||||||
| Long-term deferred revenue | 90 | 29 | — | 119 | |||||||||||||||||||
| Long-term deferred revenue - related parties | 55 | (7) | — | 48 | |||||||||||||||||||
| Long-term contract liabilities | $ | — | $ | 6 | $ | — | $ | 6 | |||||||||||||||
(1) Balance represents ASC 606 portion of each respective line item.
(2) No significant revenue was recognized related to past performance obligations in the current periods.
Remaining Performance Obligations
The table below includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) at the end of the reporting period.
As of December 31, 2021, the amounts allocated to contract assets and contract liabilities on the Consolidated Balance Sheets are $281 million and are reflected in the amounts below. This will be recognized as revenue as the obligations are satisfied, which is expected to occur over the next 22 years. Further, MPLX does not disclose variable consideration due to volume variability in the table below.
| (In millions) | |||||
| 2022 | $ | 1,850 | |||
| 2023 | 1,725 | ||||
| 2024 | 1,592 | ||||
| 2025 | 1,507 | ||||
| 2026 and thereafter | 3,283 | ||||
Total revenue on remaining performance obligations(1)(2)(3) | $ | 9,957 | |||
(1) All fixed consideration from contracts with customers is included in the amounts presented above. Variable consideration that is constrained or not required to be estimated as it reflects our efforts to perform is excluded.
(2) Arrangements deemed implicit leases and sales-type leases are excluded from this table, see further discussion about leases in Note 20.
(3) Only minimum volume commitments that are deemed fixed are included in the table above. MPLX has various minimum volume commitments in processing arrangements that vary based on the actual Btu content of the gas received. These amounts are deemed variable consideration and are excluded from the table above.
We do not disclose information on the future performance obligations for any contract with an original expected duration of one year or less.
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19. Supplemental Cash Flow Information
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| Net cash provided by operating activities included: | ||||||||||||||||||||
| Interest paid (net of amounts capitalized) | $ | 812 | $ | 821 | $ | 835 | ||||||||||||||
| Income taxes paid | 4 | 2 | 1 | |||||||||||||||||
| Cash paid for amounts included in the measurement of lease liabilities | ||||||||||||||||||||
| Payments on operating leases | 79 | 87 | 85 | |||||||||||||||||
| Interest payment under finance lease obligations | — | 1 | 1 | |||||||||||||||||
| Net cash provided by financing activities included: | ||||||||||||||||||||
| Principal payments under finance lease obligations | 2 | 9 | 5 | |||||||||||||||||
| Non-cash investing and financing activities: | ||||||||||||||||||||
| Net transfers of property, plant and equipment from materials and supplies inventories | 1 | — | 2 | |||||||||||||||||
| MPLX terminal lease classification change | — | — | 21 | |||||||||||||||||
| ROU assets obtained in exchange for new operating lease obligations | 20 | 17 | 26 | |||||||||||||||||
| ROU assets obtained in exchange for new finance lease obligations | — | 1 | 4 | |||||||||||||||||
| Fair value of common units redeemed for Wholesale Exchange | — | 340 | — | |||||||||||||||||
Contribution - common units issued(1) | $ | — | $ | — | $ | 7,722 | ||||||||||||||
(1) For 2019, includes limited partner units issued to MPC and public unitholders as consideration in the Merger. See Note 4.
The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that did not affect cash. The following is the change of additions to property, plant and equipment related to capital accruals:
| (In millions) | 2021 | 2020 | 2019 | |||||||||||||||||
| (Decrease)/increase in capital accruals | $ | 11 | $ | (244) | $ | (146) | ||||||||||||||
20. Leases
Lessee
We lease a wide variety of facilities and equipment under leases from third parties, including land and building space, office and field equipment, storage facilities and transportation equipment, while our related party leases primarily relate to ground leases associated with our refining logistics assets. Our remaining lease terms range from less than to 57 years. Some long-term leases include renewal options ranging from to 50 years and, in certain leases, also include purchase options. Renewal options and termination options were not included in the measurement of ROU assets and lease liabilities since it was determined they were not reasonably certain to be exercised.
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The components of lease cost were as follows:
| 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| (In millions) | Related Party | Third Party | Related Party | Third Party | Related Party | Third Party | |||||||||||||||||||||||||||||
| Components of lease costs: | |||||||||||||||||||||||||||||||||||
| Operating lease costs | $ | 15 | $ | 71 | $ | 14 | $ | 78 | $ | 14 | $ | 75 | |||||||||||||||||||||||
| Finance lease cost: | |||||||||||||||||||||||||||||||||||
| Amortization of ROU assets | — | 2 | — | 3 | — | 5 | |||||||||||||||||||||||||||||
| Interest on lease liabilities | — | 1 | — | 1 | — | 1 | |||||||||||||||||||||||||||||
| Total finance lease cost | — | 3 | — | 4 | — | 6 | |||||||||||||||||||||||||||||
| Variable lease cost | — | 15 | 1 | 10 | 1 | 11 | |||||||||||||||||||||||||||||
| Short-term lease cost | — | 31 | — | 52 | — | 80 | |||||||||||||||||||||||||||||
| Total lease cost | $ | 15 | $ | 120 | $ | 15 | $ | 144 | $ | 15 | $ | 172 | |||||||||||||||||||||||
Supplemental balance sheet data related to leases were as follows:
| December 31, 2021 | December 31, 2020 | ||||||||||||||||||||||
| (In millions, except % and years) | Related Party | Third Party | Related Party | Third Party | |||||||||||||||||||
| Operating leases | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Right of use assets | $ | 229 | $ | 268 | $ | 231 | $ | 309 | |||||||||||||||
| Liabilities | |||||||||||||||||||||||
| Operating lease liabilities | 1 | 59 | 1 | 63 | |||||||||||||||||||
| Long-term operating lease liabilities | 228 | 205 | 229 | 244 | |||||||||||||||||||
| Total operating lease liabilities | $ | 229 | $ | 264 | $ | 230 | $ | 307 | |||||||||||||||
| Weighted average remaining lease term | 45.2 years | 8.3 years | 46.2 years | 8.0 years | |||||||||||||||||||
| Weighted average discount rate | 5.8 | % | 4.1 | % | 5.8 | % | 4.3 | % | |||||||||||||||
| Finance leases | |||||||||||||||||||||||
| Assets | |||||||||||||||||||||||
| Property, plant and equipment, gross | $ | 11 | $ | 17 | |||||||||||||||||||
| Less: Accumulated depreciation | 4 | 8 | |||||||||||||||||||||
| Property, plant and equipment, net | 7 | 9 | |||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||
| 2 | 2 | ||||||||||||||||||||||
| 7 | 9 | ||||||||||||||||||||||
| $ | 9 | $ | 11 | ||||||||||||||||||||
| Weighted average remaining lease term | 19.4 years | 16.9 years | |||||||||||||||||||||
| Weighted average discount rate | 6.0 | % | 6.0 | % | |||||||||||||||||||
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As of December 31, 2021, maturities of lease liabilities for operating lease obligations and finance lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:
| (In millions) | Related Party Operating Leases | Third Party Operating Leases | Finance Leases | ||||||||||||||
| 2022 | $ | 15 | $ | 68 | $ | 2 | |||||||||||
| 2023 | 15 | 59 | 2 | ||||||||||||||
| 2024 | 14 | 38 | 1 | ||||||||||||||
| 2025 | 14 | 21 | 1 | ||||||||||||||
| 2026 | 14 | 18 | 1 | ||||||||||||||
| 2027 and thereafter | 575 | 109 | 8 | ||||||||||||||
| Gross lease payments | 647 | 313 | 15 | ||||||||||||||
| Less: Imputed interest | 418 | 49 | 6 | ||||||||||||||
| Total lease liabilities | $ | 229 | $ | 264 | $ | 9 | |||||||||||
Lessor
Based on the terms of fee-based transportation and storage services agreements with MPC and third parties, MPLX is considered to be the lessor under several operating lease arrangements in accordance with GAAP. These agreements have remaining terms ranging from less than one year to 8 years with renewal options ranging from one year to 5 years, with some agreements having multiple renewal options. We are also considered to be the lessor under operating lease agreements related to certain fee-based natural gas gathering, transportation and processing agreements. MPLX’s primary natural gas lease operations relate to a natural gas gathering agreement in the Marcellus Shale for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering arrangement expires in 2038 and will continue thereafter on a year-to-year basis until terminated by either party. Other significant natural gas implicit leases relate to a natural gas processing agreement in the Marcellus Shale and a natural gas processing agreement in the Southern Appalachia region for which MPLX earns minimum monthly fees for providing processing services to a single producer using a dedicated processing plant. The primary term of these natural gas processing agreements expires during 2027 and 2028, respectively, these contracts will continue thereafter on a year-to-year basis until terminated by either party.
MPLX did not elect to use the practical expedient to combine lease and non-lease components for lessor arrangements. The tables below represent the portion of the contract allocated to the lease component based on relative standalone selling price. We elected the practical expedient to carry forward historical classification conclusions until a modification of an existing agreement occurs. Once a modification occurs, the amended agreement is required to be assessed under ASC 842, to determine whether a reclassification of the lease is required.
During the second quarter of 2021 and during the first quarter of 2020, reimbursements for projects and changes to minimum volume commitments at certain L&S locations were agreed to between MPLX and MPC. These reimbursements and minimum volume commitments relate to the storage, transportation and terminal services agreements between MPLX and MPC at these locations and required the embedded leases within these agreements to be reassessed under ASC 842. As a result of the reassessment, certain leases were reclassified from an operating lease to a sales-type lease. Accordingly, the underlying assets previously shown on the Consolidated Balance Sheets associated with the sales-type leases were derecognized and the net investment in the lease (i.e., the sum of the present value of the future lease payments and the unguaranteed residual value of the assets) was recorded as a lease receivable during the respective periods. See Note 6 for the location of lease receivables and unguaranteed residual assets on the Consolidated Balance Sheets.
The difference between the net book value of the underlying assets and the net investment in the lease has been recorded as a “Contribution from MPC” in the Consolidated Statements of Equity given the impacted storage and terminal services agreements are related to a common control transaction. During the second quarter of 2021, MPLX derecognized approximately $421 million of property, plant and equipment, recorded a lease receivable of approximately $519 million, recorded an unguaranteed residual asset of approximately $14 million with the
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difference recorded as a deemed “Contribution from MPC” of $112 million. During the first quarter of 2020, MPLX derecognized approximately $171 million of property, plant and equipment, recorded a lease receivable of approximately $370 million, recorded an unguaranteed residual asset of approximately $10 million and a “Contribution from MPC” of $209 million.
Lease revenues included on the Consolidated Statements of Income during 2021, 2020 and 2019 were as follows:
| 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| (In millions) | Related Party | Third Party | Related Party | Third Party | Related Party | Third Party | |||||||||||||||||||||||||||||
| Operating leases: | |||||||||||||||||||||||||||||||||||
| Rental income | $ | 743 | $ | 376 | $ | 952 | $ | 398 | $ | 1,196 | $ | 388 | |||||||||||||||||||||||
| Sales-type leases: | |||||||||||||||||||||||||||||||||||
| Profit/(loss) recognized at the commencement date | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Interest income (Sales-type rental revenue- fixed minimum) | 431 | — | 151 | — | 6 | — | |||||||||||||||||||||||||||||
| Interest income (Revenue from variable lease payments) | 4 | — | 1 | — | 1 | — | |||||||||||||||||||||||||||||
| Sales-type lease revenue | $ | 435 | $ | — | $ | 152 | $ | — | $ | 7 | $ | — | |||||||||||||||||||||||
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of December 31, 2021:
| (In millions) | Related Party | Third Party | Total | ||||||||||||||
| 2022 | $ | 632 | $ | 213 | $ | 845 | |||||||||||
| 2023 | 563 | 207 | 770 | ||||||||||||||
| 2024 | 514 | 204 | 718 | ||||||||||||||
| 2025 | 511 | 171 | 682 | ||||||||||||||
| 2026 | 504 | 142 | 646 | ||||||||||||||
| 2027 and thereafter | 308 | 1,299 | 1,607 | ||||||||||||||
| Total minimum future rentals | $ | 3,032 | $ | 2,236 | $ | 5,268 | |||||||||||
The following is a schedule of minimum future revenue on sales-type leases as of December 31, 2021:
| (In millions) | Related Party | ||||
| 2022 | $ | 544 | |||
| 2023 | 544 | ||||
| 2024 | 538 | ||||
| 2025 | 525 | ||||
| 2026 | 422 | ||||
| 2027 and thereafter | 595 | ||||
| Total minimum future rentals | 3,168 | ||||
| Less: present value discount | 2,232 | ||||
| Lease receivable | $ | 936 | |||
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The following schedule summarizes MPLX’s investment in assets held under operating lease by major classes as of December 31, 2021 and 2020:
| December 31, | |||||||||||
| (In millions) | 2021 | 2020 | |||||||||
| Pipelines | $ | 953 | $ | 834 | |||||||
| Refining logistics | 1,146 | 1,680 | |||||||||
| Terminals | 1,290 | 1,276 | |||||||||
| Marine | 129 | 129 | |||||||||
| Gathering and transportation | 991 | 990 | |||||||||
| Processing and fractionation | 867 | 867 | |||||||||
| Land, building and other | 176 | 171 | |||||||||
| Total property, plant and equipment | 5,552 | 5,947 | |||||||||
| Less: accumulated depreciation | 2,042 | 2,007 | |||||||||
| Property, plant and equipment, net | $ | 3,510 | $ | 3,940 | |||||||
See Note 6 for additional information on where related party lease assets are recorded in the Consolidated Balance Sheets. At December 31, 2021 and 2020, third-party lease assets were less than $1 million and are included within the “Receivables, net” and “Other noncurrent assets” captions within the Consolidated Balance Sheets.
21. Commitments and Contingencies
MPLX is the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which MPLX has not recorded a liability, MPLX is unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings, discovery or court proceedings. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.
Environmental Matters – MPLX is subject to federal, state and local laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for non-compliance.
At December 31, 2021 and 2020, accrued liabilities for remediation totaled $23 million and $17 million, respectively. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, that may be imposed. At December 31, 2021 and 2020, there were no balances with MPC for indemnification of environmental costs.
MPLX is involved in environmental enforcement matters arising in the ordinary course of business. While the outcome and impact to MPLX cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its consolidated results of operations, financial position or cash flows.
MPLX is also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to MPLX cannot be predicted with certainty, management believes the resolution of these other lawsuits and proceedings will not, individually or collectively, have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Guarantees – Over the years, MPLX has sold various assets in the normal course of its business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require MPLX to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. MPLX is typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that
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there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.
We hold a 9.19 percent indirect interest in a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system or DAPL. In 2020, the U.S. District Court for the District of Columbia (the “D.D.C.”) ordered the U.S. Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The EIS is currently expected to be completed in the second half of 2022.
In May 2021, the D.D.C. denied a renewed request for an injunction to shut down the pipeline while the EIS is being prepared. In June 2021, the D.D.C. issued an order dismissing without prejudice the tribes’ claims against the Dakota Access Pipeline. The litigation could be reopened or new litigation challenging the EIS, once completed, could be filed. The pipeline remains operational.
We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of construction of the Bakken Pipeline system. If the pipeline were temporarily shut down, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is shutdown. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the permit and/or return the pipeline into operation. If the vacatur of the easement permit results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the one percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of December 31, 2021, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $230 million.
Other Legal Proceedings – In July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the Bureau of Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline that crosses the Fort Berthold Reservation in North Dakota. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. On appeal, the Assistant Secretary - Indian Affairs issued an order vacating the BIA’s trespass order and remanded to the Regional Director for the BIA Great Plains Region to issue a new decision based on specified criteria. On December 15, 2020, the Regional Director of the BIA issued a new trespass notice to THPP, finding that THPP was in trespass and assessing trespass damages of approximately $4 million (including interest), which has been paid. The order also required that THPP immediately cease and desist use of the portion of the pipeline that crosses the property at issue. THPP has complied with the Regional Director’s December 15, 2020 notice. In March 2021, THPP received a copy of an order purporting to vacate all orders related to THPP’s alleged trespass issued by the BIA between July 2, 2020 and January 14, 2021. The order directs the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order, if necessary, after all interested parties have had an opportunity to be heard. Subsequently, landowners voluntarily dismissed the suit filed in the District of North Dakota. On April 23, 2021, THPP filed a lawsuit in the District of North Dakota against the United States of America, the U.S. Department of the Interior and the BIA (together, the “U.S. Government Parties”) challenging the March order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the U.S. Government Parties filed their answer to THPP’s suit, asserting counterclaims for trespass and ejectment. The U.S. Government Parties claim THPP is in continued trespass with respect to the pipeline and seek disgorgement of pipeline profits from June 1, 2013 to present, removal of the pipeline and remediation. We intend to vigorously defend ourselves against these counterclaims. We continue to work towards a settlement of this matter with holders of the property rights at issue.
Contractual Commitments and Contingencies – At December 31, 2021, MPLX’s contractual commitments to acquire property, plant and equipment totaled $116 million. These commitments were primarily related to G&P plant expansions. In addition, from time to time and in the ordinary course of business, MPLX and its affiliates provide guarantees of MPLX’s subsidiaries payment and performance obligations in the G&P segment. Certain natural gas processing and gathering arrangements require MPLX to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel
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the processing arrangements if there are significant delays that are not due to force majeure. As of December 31, 2021, management does not believe there are any indications that MPLX will not be able to meet the construction milestones, that force majeure does not apply or that such fees and charges will otherwise be triggered.
Other Contractual Obligations – MPLX executed various third party transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the remaining terms of the agreements, which range from to 10 years. After the minimum volume commitments are met in the transportation and terminalling agreements, MPLX pays additional amounts based on throughput. There are escalation clauses in the transportation and terminalling agreements, which are based on Consumer Price Index adjustments. The minimum future payments under these agreements as of December 31, 2021 are as follows:
| (In millions) | |||||
| 2022 | $ | 117 | |||
| 2023 | 155 | ||||
| 2024 | 146 | ||||
| 2025 | 124 | ||||
| 2026 | 111 | ||||
| 2027 and thereafter | 310 | ||||
| Total | $ | 963 | |||
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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. Based upon that evaluation, the chief executive officer and chief financial officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2021, the end of the period covered by this Annual Report on Form 10-K.
Changes in Internal Control over Financial Reporting
During the quarter ended December 31, 2021, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None
Item 9C. Disclosures Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable
Part III
Item 10. Directors, Executive Officers and Corporate Governance
MANAGEMENT OF MPLX LP
MPLX GP LLC, our general partner, is a wholly owned subsidiary of MPC. Our general partner manages our operations and activities through its directors and executive officers. Our unitholders do not nominate candidates for, or vote for the election of, the directors of our general partner. Through its indirect ownership of all of the membership interests in our general partner, MPC elects all members of our general partner’s board of directors (the “Board”). Directors are elected by the sole member of our general partner and hold office until their successors have been elected or qualified or until their earlier death, resignation, removal or disqualification. Our general partner’s executive officers are appointed by, and serve at the discretion of, the Board.
References in this Part III to our “Board,” “directors” or “officers” refer to the Board, directors and officers of our general partner.
Neither we nor our subsidiaries directly employ any employees. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees who conduct our business are directly employed by affiliates of our general partner, but we sometimes refer to these individuals as our employees for ease of reference.
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DIRECTORS AND EXECUTIVE OFFICERS OF MPLX GP LLC
The directors, executive officers and corporate officers of MPLX GP LLC are as follows:
| Name | Age as of February 1, 2022 | Position with MPLX GP LLC | ||||||||||||
| Michael J. Hennigan | 62 | Chairman of the Board of Directors, President and Chief Executive Officer | ||||||||||||
| John J. Quaid | 50 | Director, Executive Vice President and Chief Financial Officer | ||||||||||||
| Christopher A. Helms | 67 | Director | ||||||||||||
| Maryann T. Mannen | 59 | Director | ||||||||||||
| Garry L. Peiffer | 70 | Director | ||||||||||||
| Dan D. Sandman | 73 | Director | ||||||||||||
| Frank M. Semple | 70 | Director | ||||||||||||
| J. Michael Stice | 62 | Director | ||||||||||||
| John P. Surma | 67 | Director | ||||||||||||
| Timothy J. Aydt | 58 | Executive Vice President and Chief Commercial Officer | ||||||||||||
| Gregory S. Floerke | 58 | Executive Vice President and Chief Operating Officer | ||||||||||||
Raymond L. Brooks* | 61 | Executive Vice President | ||||||||||||
| Suzanne Gagle | 56 | General Counsel | ||||||||||||
Rick D. Hessling* | 55 | Senior Vice President | ||||||||||||
| Thomas Kaczynski | 60 | Senior Vice President, Finance and Treasurer | ||||||||||||
Brian K. Partee* | 48 | Senior Vice President | ||||||||||||
Molly R. Benson* | 55 | Vice President, Chief Securities, Governance & Compliance Officer and Corporate Secretary | ||||||||||||
Kristina A. Kazarian* | 39 | Vice President, Investor Relations | ||||||||||||
Shawn M. Lyon* | 54 | Vice President, Operations | ||||||||||||
| Kelly D. Wright | 39 | Vice President and Controller | ||||||||||||
* Corporate officer
Mr. Hennigan was appointed Chief Executive Officer effective November 2019 and has served as President since June 2017. He has served on the Board of Directors since June 2017 and was appointed Chairman of the Board effective April 2020. He has served as MPC’s President and Chief Executive Officer since March 2020, and on its Board of Directors since April 2020. Prior to joining us in 2017, Mr. Hennigan was President, Crude, NGL and Refined Products of the general partner of Energy Transfer Partners L.P., an energy service provider. He was President and Chief Executive Officer of Sunoco Logistics Partners L.P., an oil and gas transportation, terminalling and storage company, from 2012 to 2017, President and Chief Operating Officer beginning in 2010, and Vice President, Business Development beginning in 2009. Mr. Hennigan holds a bachelor’s degree in chemical engineering from Drexel University.
Qualifications: Mr. Hennigan brings to the Board a unique perspective and valued guidance gained from nearly 40 years of industry experience, including as our Chairman, President and Chief Executive Officer, MPC’s President and Chief Executive Officer, and as the President and Chief Executive Officer of a successful growth-oriented master limited partnership.
Other Public Company Directorships within Past Five Years: Marathon Petroleum Corporation (since 2020); Sunoco Partners LLC (2010-2017); Tesoro Logistics GP, LLC (2018-2019)
Mr. Quaid was appointed Executive Vice President and Chief Financial Officer effective September 2021, and was elected a member of the Board effective January 2022. He previously served as MPC’s Senior Vice President and Controller beginning in April 2020, and Vice President and Controller beginning in 2014. Before joining MPC, Mr. Quaid was Vice President of Iron Ore at United States Steel Corporation, an integrated steel producer, beginning in 2014, and Vice President and Treasurer beginning in 2011, having previously served in various functions including investor relations, business planning, financial planning and analysis and project management. Mr. Quaid holds a bachelor’s degree in accounting from Lehigh University.
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Qualifications: As our Chief Financial Officer, Mr. Quaid brings to the Board direct insight into all financial aspects of our business, including in the areas of accounting, risk management and financial management. His background in business planning, treasury and finance affords him an extensive understanding of strategic and financial planning, accounting, internal controls, public company financial reporting requirements and related matters.
Other Public Company Directorships within Past Five Years: None within the last five years
Mr. Helms was elected a member of the Board effective October 2012. Mr. Helms is President and Chief Executive Officer of US Shale Management Company, a wholly-owned subsidiary of US Shale Energy Advisors LLC. Mr. Helms is the co-founder of US Shale Energy Advisors LLC, a privately owned entity engaged in the development, ownership and operation of midstream energy assets. Through subsidiaries it owns and operates Rocky Mountain Crude Oil LLC, a crude oil logistics company focused on the transportation of crude oil produced in the great plains and Rocky Mountain regions of the U.S. From 2005 until his retirement in 2011, Mr. Helms served in various capacities with NiSource Inc. and its affiliate, NiSource Gas Transmission and Storage, including as Executive Vice President and Group Chief Executive Officer. He was Group President, Pipeline of NiSource Inc. from 2005 to 2008, where he was also a member of the Executive Council and the Corporate Risk Management Committee. He served as Chief Executive Officer and Executive Director of NiSource Gas Transmission and Storage from 2008 to 2011. At NiSource, Mr. Helms was responsible for leading the company’s interstate gas transmission, storage and midstream businesses. Prior to joining NiSource, Mr. Helms held senior executive positions with CMS Energy Corporation, and subsidiaries of Duke Energy Corporation and PanEnergy Corp. from 1990 to 2005. Mr. Helms holds a bachelor’s degree from Southern Illinois University at Edwardsville and a juris doctor degree from the Tulane University School of Law.
Qualifications: Mr. Helms brings to the Board considerable midstream energy expertise, particularly in operations and business combinations, as well as experience in finance, accounting, compliance, strategic planning and risk oversight. His background also includes overseeing joint ventures and mergers and acquisitions within the midstream energy sector and supervising financial reporting functions.
Other Public Company Directorships within Past Five Years: Range Resources Corporation (2014-2019)
Ms. Mannen was elected a member of the Board in February 2021. She was appointed Executive Vice President and Chief Financial Officer of MPC effective January 25, 2021. Before joining MPC, she served as Executive Vice President and Chief Financial Officer of TechnipFMC (a successor to FMC Technologies, Inc.), a global leader in subsea, onshore/offshore, and surface projects for the energy industry, since 2017, having previously served as Executive Vice President and Chief Financial Officer of FMC Technologies, Inc. since 2014, Senior Vice President and Chief Financial Officer since 2011, and in various positions of increasing responsibility with FMC Technologies, Inc. since 1986. Ms. Mannen holds a bachelor's degree in accounting and a master’s degree in business administration from Rider University.
Qualifications: Ms. Mannen brings to the Board significant leadership experience in finance, international operations and management. Her experience as Chief Financial Officer at large, publicly traded energy sector companies enables her to contribute important insights regarding finance, risk management, public company financial reporting requirements and related matters.
Other Public Company Directorships within Past Five Years: Owens Corning (since 2014)
Mr. Peiffer was elected a member of the Board in June 2012, and served as our President from 2012 until his retirement in 2014. He also served as MPC’s Executive Vice President, Corporate Planning and Investor & Government Relations from 2011 until his retirement. He is a member of the board of directors of Fifth Third Bank (Northern Ohio) and Roppe Corporation, a privately held company. Mr. Peiffer is also a member of the board of trustees of the Findlay-Hancock County Community Foundation and the boards of the Catholic Community Foundation-Ohio and the Blanchard Valley Port Authority. He began his career with Marathon in 1974, where he held a variety of management positions with increasing responsibility, including as Supervisor of Employee Savings and Retirement Plans, Controller of Speedway Petroleum Corporation and numerous other marketing and logistics positions. In 1987, Mr. Peiffer was appointed to the President’s Commission on Executive Exchange serving for a year in the Pentagon as Special Assistant to the Assistant Secretary of Defense for Production and Logistics. In 1988, he returned to Marathon and was named Vice President of Finance and Administration for Emro Marketing Company. He served as Assistant Controller, Refining, Marketing and Transportation beginning in 1992. He was named Senior Vice President of Finance and Commercial Services for Marathon Ashland Petroleum LLC in 1998
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and Executive Vice President of MPC in 2011. Mr. Peiffer holds a bachelor’s degree in accounting from Bowling Green State University and passed the certified public accountant exam in Ohio.
Qualifications: As the retired President of our general partner and retired Executive Vice President, Corporate Planning and Investor & Government Relations of MPC, Mr. Peiffer brings to the Board extensive experience in the energy industry gained from his roles at MPC and its affiliates. His significant career accomplishments include leading us through the initial public offering process and our first year of operations, leading finance organizations, successfully completing several joint ventures and corporate reorganizations and implementing new information technology solutions.
Other Public Company Directorships within Past Five Years: None within the last five years
Mr. Sandman was elected a member of the Board effective October 2012. Mr. Sandman is an adjunct professor at The Ohio State University Moritz College of Law, where he has taught corporate governance law since 2007. He has served on the board of directors of Roppe Corporation, a privately held company, since 1987. Additionally, Mr. Sandman serves on the boards of directors of the Carnegie Science Center, the Carnegie Hero Commission and Grove City College. He has served as a court-appointed mediator of commercial cases pending in U.S. federal courts and has lectured on corporate governance law at Oxford University. Mr. Sandman began his career with Marathon in 1973, serving in various legal positions of increasing responsibility, ultimately being named General Counsel and Secretary of Marathon in 1986. In 1993, he was named General Counsel and Secretary of USX Corporation. Upon the spinoff of United States Steel Corporation from USX in 2002, Mr. Sandman was named Vice Chairman of the Board of Directors and Chief Legal and Administrative Officer of United States Steel, where he served until his retirement in 2007. During his time with United States Steel, Mr. Sandman was also responsible at various times for management and oversight of aspects of Human Resources, Executive Compensation, Public Relations, Environmental and Government Affairs, the Law Organization and the Corporate Secretary’s office. Mr. Sandman holds a bachelor’s degree from The Ohio State University and a juris doctor degree from The Ohio State University College of Law, and he attended the Stanford Executive Program in 1989.
Qualifications: Mr. Sandman brings to the Board considerable experience in legal and business affairs, transactional law, regulatory compliance and corporate governance, ethics and risk management matters, as well as an energy industry background.
Other Public Company Directorships within Past Five Years: CONSOL Coal Resources GP LLC (2017-2020)
Mr. Semple was elected a member of the Board effective December 2015, at the time of the MarkWest Merger. He was appointed our Vice Chairman at the close of the MarkWest Merger and served in that position until his retirement in October 2016. He also served on the MPC Board of Directors from December 2015 until October 2018. Prior to joining us, Mr. Semple served as President and Chief Executive Officer of MarkWest beginning in 2003, and as Chairman of the Board beginning in 2008. Prior to his time at MarkWest, he served 22 years with The Williams Companies, Inc. and WilTel Communications, including as Chief Operating Officer of WilTel Communications, Senior Vice President/General Manager of Williams Natural Gas Company, Vice President of Operations and Engineering for Northwest Pipeline Company and division manager for Williams Pipe Line Company. Prior to joining Williams, Mr. Semple served in the United States Navy. He holds a bachelor’s degree in mechanical engineering from the United States Naval Academy and has completed the Program for Management Development at Harvard Business School.
Qualifications: Mr. Semple brings to the Board proven leadership ability in managing a complex business and a deep understanding of the midstream sector gained from his experience as Chairman and Chief Executive Officer of MarkWest, as well as significant experience regarding operations, strategic planning, finance and corporate governance matters.
Other Public Company Directorships within Past Five Years: Marathon Petroleum Corporation (2015-2018; since 2021); Tesoro Logistics GP, LLC (2018-2019); Tortoise Acquisition Corp (2019-2020)
Mr. Stice was elected a member of the Board effective April 2018, and as a member of the MPC Board of Directors in February 2017. He has served as the Dean of the Mewbourne College of Earth & Energy at The University of Oklahoma since 2015. Mr. Stice retired as the Chief Executive Officer of Access Midstream Partners L.P., a gathering and processing master limited partnership, in 2014 and from its board of directors in 2015. He had served as Chief Executive Officer of Access Midstream and previously, Chesapeake Midstream Partners, L.P., since 2009,
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and as President and Chief Operating Officer of Chesapeake Midstream Development, L.P. and Senior Vice President of natural gas projects of Chesapeake Energy Corporation since 2008. Mr. Stice began his career in 1981 with Conoco, serving in a variety of positions of increasing responsibility. He was named President of ConocoPhillips Qatar in 2003. Mr. Stice holds a bachelor’s degree in chemical engineering from the University of Oklahoma, a master’s degree in business from Stanford University and a doctorate in education from George Washington University.
Qualifications: Mr. Stice brings to the Board extensive experience with MLPs, including as Chief Executive Officer of one of the largest publicly traded gathering and processing MLPs, and as a member of the board of directors of MarkWest, which we acquired in 2015. He has forty years of experience in the upstream and midstream gas businesses.
Other Public Company Directorships within Past Five Years: Marathon Petroleum Corporation (since 2017); Spartan Acquisition Corp. II (since 2020); Spartan Acquisition Corp. III (since 2021); Spartan Energy Acquisition Corporation (2018-2020); U.S. Silica Holdings, Inc. (2013-2021)
Mr. Surma was elected a member of the Board effective October 2012, and as a member of the MPC Board of Directors in July 2011. He has served as Chairman of the Board of MPC since April 2020. Mr. Surma retired as the Chief Executive Officer and Executive Chairman of United States Steel Corporation, an integrated steel producer, in 2013. Prior to joining United States Steel, he served in several executive positions with Marathon, including as Senior Vice President, Finance & Accounting of Marathon Oil Company in 1997; President, Speedway SuperAmerica LLC in 1998; Senior Vice President, Supply & Transportation of Marathon Ashland Petroleum LLC in 2000; and President of Marathon Ashland Petroleum in 2001. Prior to joining Marathon, Mr. Surma worked for Price Waterhouse LLP, becoming a partner in 1987. In 1983, he participated in the President’s Executive Exchange Program in Washington, D.C., serving as Executive Staff Assistant to the Federal Reserve Board’s Vice Chairman. Mr. Surma is on the board of the University of Pittsburgh Medical Center, and formerly chaired the boards of the Federal Reserve Bank of Cleveland and the National Safety Council. He was appointed by President Barack Obama to the President’s Advisory Committee for Trade Policy and Negotiations, serving from 2010 to 2014, including as Vice Chairman. Mr. Surma holds a bachelor’s degree in accounting from Pennsylvania State University.
Qualifications: Mr. Surma brings to the Board a broad range of experience as the retired Chairman and Chief Executive Officer of a large industrial firm, and the current Chairman of MPC, and provides valuable input on our strategic direction and operations. He also has significant experience in public accounting and in executive leadership in the energy and steel industries.
Other Public Company Directorships within Past Five Years: Concho Resources Inc. (2014-2020); Marathon Petroleum Corporation (since 2011); Public Service Enterprise Group Inc. (since 2019); Trane Technologies plc (formerly Ingersoll-Rand plc) (since 2013)
Mr. Aydt was appointed Executive Vice President and Chief Commercial Officer effective August 2020. Prior to this appointment, he served as Vice President, Business Development, beginning in November 2018, Vice President, Operations, and President of Marathon Pipe Line LLC beginning in January 2017, MPC’s Terminal, Transport and Rail General Manager beginning in 2013, and Project Director for the $2.2 billion Detroit Heavy Oil Upgrade Project beginning in 2008. Mr. Aydt chairs the board of the Louisiana Offshore Oil Port (LOOP).
Mr. Floerke was appointed Executive Vice President and Chief Operating Officer effective August 2020. Prior to this appointment, he served as Executive Vice President, Gathering and Processing, beginning in 2018, Executive Vice President and Chief Operating Officer, MarkWest Operations, beginning in July 2017, and Executive Vice President and Chief Commercial Officer, MarkWest Assets, beginning in 2015, at the time of the MarkWest Merger. Before joining us, Mr. Floerke was Executive Vice President and Chief Commercial Officer at MarkWest beginning in 2015, and Senior Vice President, Northeast region, at MarkWest beginning in 2013. Previously, Mr. Floerke held senior management positions at Access Midstream Partners, L.P., a gathering and processing master limited partnership, from 2011 until 2013.
Mr. Brooks was appointed Executive Vice President effective February 2021. Prior to this appointment, he served as Senior Vice President beginning in February 2018, and MPC’s Executive Vice President, Refining, beginning in October 2018, MPC’s Senior Vice President, Refining, beginning in March 2016, General Manager of MPC’s Galveston Bay, Texas, refinery beginning in 2013, General Manager of MPC’s Robinson, Illinois, refinery beginning in 2010, and General Manager of MPC’s St. Paul Park, Minnesota, refinery beginning in 2006.
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Ms. Gagle was appointed General Counsel effective October 2017. She was appointed MPC’s General Counsel and Senior Vice President, Government Affairs, effective February 24, 2021. Prior to this appointment, she served as MPC’s General Counsel beginning in March 2016, Assistant General Counsel, Litigation and Human Resources, beginning in 2011, Senior Group Counsel, Downstream Operations, beginning in 2010, and Group Counsel, Litigation, beginning in 2003.
Mr. Hessling was appointed Senior Vice President effective October 2018. He was appointed MPC’s Senior Vice President, Global Feedstocks, effective February 24, 2021, having served as MPC’s Senior Vice President, Crude Oil Supply and Logistics since October 2018. Prior to this appointment, Mr. Hessling served as MPC’s Manager, Crude Oil & Natural Gas Supply and Trading beginning in 2014, and Crude Oil Logistics & Analysis Manager beginning in 2011.
Mr. Kaczynski was appointed Senior Vice President, Finance, and Treasurer effective February 24, 2021, having served as Vice President, Finance and Treasurer since December 2020. He was appointed MPC’s Senior Vice President, Finance, and Treasurer effective February 24, 2021, having served as MPC’s Vice President, Finance, and Treasurer since 2015. Prior to joining MPC, Mr. Kaczynski was Vice President and Treasurer of Goodyear Tire and Rubber Company, one of the world’s largest tire manufacturers, beginning in 2014, and Vice President, Investor Relations beginning in 2013.
Mr. Partee was appointed Senior Vice President effective October 2018. He was appointed MPC’s Senior Vice President, Global Clean Products, effective February 24, 2021, having served as MPC’s Senior Vice President, Marketing, since October 2018. Prior to this appointment, Mr. Partee served as MPC’s Vice President, Business Development, beginning in February 2018, Director of Business Development beginning in January 2017, Manager of Crude Oil Logistics beginning in 2014, and Vice President, Business Development and Franchise, at Speedway beginning in 2012.
Ms. Benson was appointed Vice President, Chief Securities, Governance & Compliance Officer and Corporate Secretary for MPC and us effective June 2018, having previously served as Vice President, Chief Compliance Officer and Corporate Secretary for MPC and us since March 2016. Prior to her 2016 appointment, Ms. Benson was MPC’s Assistant General Counsel, Corporate and Finance beginning in 2012, and Group Counsel, Corporate and Finance beginning in 2011.
Ms. Kazarian was appointed Vice President, Investor Relations, for MPC and us effective April 2018. Prior to this appointment, she was Managing Director and head of the MLP, Midstream and Refining Equity Research teams at Credit Suisse, a global investment bank and financial services company, beginning in September 2017. Previously, Ms. Kazarian was Managing Director of MLP, Midstream and Natural Gas Equity Research at Deutsche Bank, a global investment bank and financial services company, beginning in 2014, and an analyst specializing on various energy industry subsectors with Fidelity Management & Research Company, a privately held investment manager, beginning in 2005.
Mr. Lyon was appointed Vice President, Operations, and President, Marathon Pipe Line LLC, effective November 2018. Prior to this appointment, he was Vice President of Operations for Marathon Pipe Line LLC beginning in 2011. Previously, Mr. Lyon served in various roles of increasing responsibility with MPC since 1989, including as Manager, Marketing and Transportation Engineering beginning in 2010, and District Manager, Transport and Rail beginning in 2008.
Ms. Wright was appointed Vice President and Controller effective September 2021. Prior to this appointment, she served as Assistant Controller of MPC since February 2019, having previously served as Senior Director Accounting Operations Excellence since October 2018. Prior to MPC’s acquisition of Andeavor in October 2018, Ms. Wright served in various roles of increasing responsibility at Andeavor, including Deputy Controller of Value Chain Accounting from April 2018 to October 2018, Director of M&A Finance Integration from January 2017 to April 2018, and Assistant Controller Logistics from March 2015 to January 2017. Prior to joining Andeavor in 2010, she spent five years in public accounting with KPMG LLP.
GOVERNANCE FRAMEWORK
Our Governance Principles provide the functional framework of our Board. They address, among other things, the primary roles, responsibilities and oversight functions of the Board and its committees, director independence, committee composition, the process for director selection, director qualifications, outside commitments, director
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compensation and director retirement and resignation. Our Governance Principles provide that directors generally must retire from service once they reach age 75, unless otherwise approved by the general partner’s sole member.
Our Code of Business Conduct, which applies to all of our directors, officers and employees, defines our expectations for ethical decision-making, accountability and responsibility. Our Code of Ethics for Senior Financial Officers, which is specifically applicable to our Chief Executive Officer, Chief Financial Officer, Controller, and other leaders performing similar roles, affirms the principle that the honesty, integrity and sound judgment of our senior executives with responsibility for preparation and certification of our financial statements are essential to the proper functioning and success of our company. Printed copies of these documents are available upon request to our Corporate Secretary. We will post on our website any amendments to, or waivers from, either of these codes requiring disclosure under applicable rules within four business days of the amendment or waiver.
Our Whistleblowing as to Accounting Matters Policy establishes procedures for the receipt, retention and treatment of complaints we receive regarding accounting, internal accounting controls or auditing matters, and provides for the confidential, anonymous submission of concerns by employees or others regarding questionable accounting or auditing matters.
Copies of the Governance Principles, the Code of Business Conduct, the Code of Ethics for Senior Financial Officers, and the Whistleblowing as to Accounting Matters Policy are available on the “Corporate Governance” page of our website at www.mplx.com/Investors/Corporate_Governance/.
DIRECTOR INDEPENDENCE AND QUALIFICATIONS
The Board currently consists of nine directors. The NYSE does not require a publicly traded limited partnership like us to have a majority of independent directors on our Board. We are, however, required to have an Audit Committee comprised of at least three independent directors. The Board considered all relevant facts and circumstances including, without limitation, transactions between the director directly or organizations with which the director is affiliated and us, any service by the director on the board of a company with which we conduct business, and the frequency and dollar amounts associated with these transactions, and has determined that each of Messrs. Helms, Peiffer, Sandman, Semple, Stice and Surma meets the independence standards in our Governance Principles, has no material relationship with us other than as a director, and satisfies the independence requirements of the NYSE and applicable SEC rules.
As stated above, our Governance Principles address qualifications for serving as a director. Directors must actively be engaged in their profession or otherwise regularly involved in business, professional or academic communities, and must normally be available for meetings of the Board and its committees. Directors are encouraged to serve on the boards of directors of other companies; however, each director’s outside directorships must be limited to a number that does not interfere with his or her ability to meet the responsibilities and expectations of service on our Board. Messrs. Semple, Stice and Surma currently serve on MPC’s board of directors. As MPLX GP LLC is a wholly owned subsidiary of MPC, we view such service as an extension of service on our Board for purposes of assessing the level of outside public board commitments.
BOARD LEADERSHIP STRUCTURE
Our Governance Principles provide the Board with the flexibility to determine from time to time the optimal leadership for the Board depending upon our particular needs and circumstances. The Board has determined that Mr. Hennigan is in the best position at this time to serve as Chairman due to his extensive knowledge of all aspects of our business, as well as our continued relationship with MPC.
When the CEO or another management director is elected Chairman, the Board has appointed an independent director as “Lead Director” to provide independent director oversight and preside over executive sessions of the Board or other Board meetings when the Chairman is absent.
Mr. Sandman, an independent director, currently serves as Lead Director of the Board. The Board believes that this leadership structure is in the best interests of our unitholders and us at this time because it strikes an effective balance between management and independent director participation in the Board process.
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COMMITTEES OF THE BOARD
Our Board has a standing Audit Committee and Conflicts Committee, and may have such other committees as the Board shall determine from time to time. Each committee operates under a written charter, which is available on the “Corporate Governance” page of our website at www.mplx.com/Investors/Corporate_Governance/. Each charter requires the applicable committee to annually assess and report to the Board on the adequacy of the charter.
We have additionally established an executive committee of the board, comprised of Messrs. Hennigan and Sandman, to address matters that may arise between meetings of the Board. This executive committee may exercise the powers and authority of the Board subject to specific limitations consistent with applicable law.
Because we are a limited partnership, we are not required to have a compensation committee or a nominating/corporate governance committee.
Audit Committee
Our Audit Committee assists the Board in its oversight of the integrity of our financial statements, and our compliance with legal and regulatory requirements and our disclosure controls and procedures. Our Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. Our Audit Committee also is responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to our Audit Committee.
Our Audit Committee is comprised of Messrs. Peiffer (Chair), Helms and Sandman. The Board has determined that each member of the Audit Committee meets the independence requirements of the NYSE and the SEC, as applicable, and that each is financially literate. The Board also has determined that each of Messrs. Peiffer and Sandman qualifies as an “audit committee financial expert,” as defined by SEC rules, based on the attributes, education and experience further described in each director’s biography under “Directors and Executive Officers of MPLX GP LLC,” above.
Audit Committee Report
The Audit Committee has reviewed and discussed MPLX’s audited financial statements and its report on internal control over financial reporting for 2021 with the management of MPLX GP LLC, MPLX’s general partner. The Audit Committee discussed with the independent auditors, PricewaterhouseCoopers LLP, the matters required to be discussed by the applicable requirements of the Public Company Accounting Oversight Board and the SEC. The Audit Committee has received the written disclosures and the letter from PricewaterhouseCoopers LLP required by the applicable requirements of the Public Company Accounting Oversight Board regarding PricewaterhouseCoopers LLP’s communications with the Audit Committee concerning independence, and has discussed with PricewaterhouseCoopers LLP its independence. Based on the review and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements and the report on internal control over financial reporting for MPLX LP be included in MPLX’s Annual Report on Form 10-K for the year ended December 31, 2021, for filing with the SEC.
Garry L. Peiffer, Chair
Christopher A. Helms
Dan D. Sandman
Conflicts Committee
Our Conflicts Committee reviews specific matters that may involve conflicts of interest in accordance with the terms of our Partnership Agreement. Any matters approved by our Conflicts Committee in good faith will be deemed to be approved by all of our partners and not a breach by our general partner of any duties it may owe our unitholders or us. The members of our Conflicts Committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence and experience standards established by the NYSE and the SEC to serve on an audit committee. In addition, the members of our Conflicts Committee may not own any interest in our general partner or any interest in us, our subsidiaries or our affiliates other than common units or awards under our incentive compensation plan.
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Our Conflicts Committee is comprised of Messrs. Helms (Chair) and Sandman. The Board has determined that each member of the Conflicts Committee meets the independence requirements of the NYSE and the SEC, as applicable.
COMMUNICATING WITH THE BOARD
All interested parties, including unitholders, may communicate directly with the Board, the Chairs of the Board’s standing committees and the independent directors as follows:
Mail: Communications may be sent by regular mail to our principal executive offices, to the attention of the Corporate Secretary, MPLX GP LLC, 200 East Hardin Street, Findlay, OH 45840.
Email:
•Independent Directors (individually or as a group): non-managedirectors@mplx.com
•Audit Committee Chair: auditchair@mplx.com
•Conflicts Committee Chair: conflictschair@mplx.com
Our Corporate Secretary will forward to the directors all communications that, in her judgment, are appropriate for consideration by the directors. Examples of communications that would not be considered appropriate include commercial solicitations and matters not relevant to the Partnership’s affairs.
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Item 11. Executive Compensation
COMPENSATION DISCUSSION AND ANALYSIS
This Compensation Discussion and Analysis (“CD&A”) provides an overview of our executive compensation program and explains how and why 2021 compensation decisions were made for our named executive officers listed below (our “NEOs”). We recommend this section be read together with the tables and related disclosures in the “Executive Compensation Tables” section of this Item 11.
NAMED EXECUTIVE OFFICERS
This CD&A focuses on the compensation for our NEOs, which for 2021 included our Chairman, President and Chief Executive Officer (“CEO”), our current and former Executive Vice President and Chief Financial Officer (“CFO”), and three other most highly compensated executive officers:
| Name | Title | |||||||
| Michael J. Hennigan | Chairman, President and CEO | |||||||
| John J. Quaid | Executive Vice President and CFO (effective September 1, 2021) | |||||||
| Suzanne Gagle | General Counsel | |||||||
| Gregory S. Floerke | Executive Vice President and Chief Operating Officer | |||||||
| Timothy J. Aydt | Executive Vice President and Chief Commercial Officer | |||||||
| Pamela K.M. Beall | Former Executive Vice President and CFO (until September 1, 2021) | |||||||
COMPENSATION DECISIONS AND ALLOCATION
Compensation Allocation
We do not directly employ any of the personnel responsible for managing and operating our business, including our NEOs. Instead, we contract with MPC to provide the necessary personnel, all of whom are directly employed by MPC or one of its affiliates. Under the terms of an omnibus agreement, described in Item 8. Financial Statements and Supplementary Data, Note 6 of this report, we pay MPC a fixed amount in return for services provided by our NEOs, which totaled approximately $14.6 million for 2021. Although we report in this CD&A 100% of the compensation our NEOs receive for their service to MPC and its affiliates (including us), the only direct compensation we provide to our NEOs is in the form of long-term equity incentive awards, which are described in detail in the “2021 Grants of Plan-Based Awards” table and accompanying narrative below.
Compensation Decisions
We maintain the MPLX LP 2018 Incentive Compensation Plan (the “MPLX 2018 Plan”) for the benefit of eligible officers, employees and directors of our general partner and its affiliates, including MPC, who provide services to our business. The Compensation and Organization Development Committee of MPC’s board of directors (“MPC’s Compensation Committee”), currently comprised of five independent directors, recommends awards under the MPLX 2018 Plan for our NEOs, subject to approval by our Board, which typically considers such awards on an annual basis. Our Board makes all final determinations with respect to awards under the MPLX 2018 Plan. All other compensation decisions for our NEOs are made by MPC's Compensation Committee and are not subject to approval by our Board or us.
Compensation Consultant
Our Board does not have a standing compensation committee and has not hired its own compensation consultant. MPC’s Compensation Committee engages an independent compensation consultant to provide compensation consulting services and comparative compensation information.
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EXECUTIVE COMPENSATION PROGRAM FOR 2021
2021 Base Salary
MPC pays our NEOs a base salary for their services to MPC and its affiliates, including us. In setting base salary for 2021, MPC’s Compensation Committee evaluated compensation reference group data, each individual’s performance and contributions over the prior year, where applicable, demonstrated performance and skills acquired over the course of each NEO’s career and MPC’s succession-planning needs. Taking these matters into consideration, MPC’s Compensation Committee approved the following 2021 base salaries for our NEOs:
| Name | Previous Base Salary ($) | Base Salary Effective Apr. 1, 2021 ($) | Increase (%) | ||||||||||||||||||||||||||
| Hennigan | 1,600,000 | 1,600,000 | — | ||||||||||||||||||||||||||
| Quaid | 550,000 | 575,000 | * | 5 | |||||||||||||||||||||||||
| Gagle | 700,000 | 700,000 | — | ||||||||||||||||||||||||||
| Floerke | 560,000 | 560,000 | — | ||||||||||||||||||||||||||
| Aydt | 400,000 | 500,000 | 25 | ||||||||||||||||||||||||||
| Beall | 575,000 | 575,000 | — | ||||||||||||||||||||||||||
| * Effective as of September 1, 2021. | |||||||||||||||||||||||||||||
As noted above in “Compensation Allocation,” under our omnibus agreement, we pay MPC a fixed amount in return for services provided by our NEOs. The amounts shown in this table were paid to our NEOs by MPC.
Mr. Aydt’s base salary was increased in recognition of the additional responsibilities he assumed upon his promotion to Executive Vice President and Chief Commercial Officer in late 2020. Mr. Quaid did not receive a base salary increase in April; however, his base salary was increased effective September 1, 2021, in recognition of the additional responsibilities he assumed upon his promotion to Executive Vice President and Chief Financial Officer as of that date. Other than these two increases associated with promotions, no NEO received a base salary increase for 2021, as MPC’s Compensation Committee determined to focus any compensation increases on performance-based, at-risk compensation.
2021 Annual Cash Bonus Program
Our current NEOs participated in MPC’s 2021 Annual Cash Bonus (“ACB”) program, which MPC’s Compensation Committee approved in February 2021, as part of their compensation for the services they provide to MPC and its affiliates, including us. The primary purpose of the 2021 ACB program is to incentivize and reward eligible employees for executing on MPC’s strategy. MPC determined awards to our NEOs under the ACB program without input from our Board. Awards under the ACB program for our NEOs were calculated as follows:
| Eligible Earnings | × | Bonus Target | × | Performance | = | Final Award | ||||||||||||||
Eligible Earnings generally refers to the NEO’s year-end base salary rate. In an NEO’s year of hire or separation, eligible earnings is calculated as the sum of base wages paid during the year plus compensation deferred during the year, which has the effect of prorating the award. | ||||||||||||||||||||
Bonus Target is a percentage of each NEO’s eligible earnings. MPC’s Compensation Committee generally approves bonus target opportunities for our NEOs based on analysis of market-competitive data for MPC’s compensation reference group, while also taking into consideration each executive’s experience, relative scope of responsibility and potential, other market data and any other information MPC’s Compensation Committee deems relevant in its discretion. | ||||||||||||||||||||
Performance metrics and levels are established by MPC’s Compensation Committee at the beginning of the performance year. Once the performance year has ended, MPC’s Compensation Committee reviews and assesses company performance against the performance metrics and levels, as well as any other factors MPC’s Compensation Committee deems relevant in its discretion, including the NEOs’ organizational and individual performance. | ||||||||||||||||||||
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•There is no guaranteed minimum ACB payout. | ||||||||||||||||||||
•Payout results may be above or below target based on actual company and individual performance. | ||||||||||||||||||||
•Payouts are capped at 200% of each NEO’s target award. | ||||||||||||||||||||
•No upward individual performance adjustments may be made for the CEO; such adjustments for other NEOs are capped at 15%. | ||||||||||||||||||||
2021 MPC Company Metrics and Performance
MPC's 2021 ACB program emphasized pre-established financial and ESG performance measures. The following table provides each metric’s target weighting, performance levels and actual performance achieved in 2021 ($ in millions):
| Performance Metric | Target Weighting | Threshold 50% Payout | Target 100% Payout | Maximum 200% Payout | Result | Performance Achieved | |||||||||||||||||
80% | FINANCIAL | ||||||||||||||||||||||
Operating Income Per Barrel | 20% | 5th or 6th Position | 3rd or 4th Position | 1st or 2nd Position | 1st or 2nd Position | 40% | |||||||||||||||||
(200% of target) | |||||||||||||||||||||||
Adjusted EBITDA per Share | 20% | $5.28 | $6.60 | $7.92 | $11.81 | 40% | |||||||||||||||||
(200% of target) | |||||||||||||||||||||||
| Distributable Cash Flow at MPLX per Unit | 20% | $3.62 | $4.02 | $4.22 | $4.66 | 40% | |||||||||||||||||
(200% of target) | |||||||||||||||||||||||
| Refining Operating Costs (in millions) | 20% | $5,495 | $5,338 | $5,076 | $5,175 | 32.44% | |||||||||||||||||
(162.21% of target) | |||||||||||||||||||||||
20% | ENVIRONMENTAL, SOCIAL & GOVERNANCE | ||||||||||||||||||||||
Greenhouse Gas Intensity | 5% | 24.0 | 23.4 | 22.5 | 23.1 | 6.67% | |||||||||||||||||
(133.33% of target) | |||||||||||||||||||||||
Process Safety Events Rate | 5% | 0.50 | 0.33 | 0.25 | 0.41 | 3.82% | |||||||||||||||||
(76.47% of target) | |||||||||||||||||||||||
Designated Environmental Incidents | 5% | 80 | 60 | 30 | 55 | 5.83% | |||||||||||||||||
(116.67% of target) | |||||||||||||||||||||||
| Diversity, Equity & Inclusion | 5% | External hires are at least (Women/BIPOC): | 23% / 32% | 3.75% | |||||||||||||||||||
| 28% / 27% | 30% / 30% | 34% / 34% | (75% of target) | ||||||||||||||||||||
| 100% TOTAL TARGET WEIGHTING | Total Achieved: | 173% | |||||||||||||||||||||
Operating Income Per Barrel of crude oil throughput compared to a group of MPC’s peer companies: BP p.l.c.; Chevron Corporation; Exxon Mobil Corporation; HollyFrontier Corporation; PBF Energy Inc.; Phillips 66; and Valero Energy Corporation. | ||
Adjusted EBITDA per Share is a non-GAAP performance metric derived from MPC’s consolidated financial statements. It is calculated as MPC’s earnings before interest and financing costs, interest income, income taxes, depreciation and amortization expense, adjusted for certain items, including impairment expenses, inventory market valuation adjustments, effects of acquisitions and divestitures and certain other non-cash charges and credits. See Exhibit 99.1 to MPC’s Current Report on Form 8-K, filed with the SEC on February 2, 2022, for more information about Adjusted EBITDA. Adjusted EBITDA per share is determined by dividing Adjusted EBITDA by the share count on the final day of the performance period. | ||
Distributable Cash Flow at MPLX per Unit is a non-GAAP measure reflecting cash flow available to be paid to our common unitholders, as disclosed in our consolidated financial statements. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information for more information about this non-GAAP measure. DCF per unit is determined by dividing DCF by the average unit count during the performance period. | ||
Refining Operating Costs includes expenses related to employee and contract labor, maintenance, energy and chemicals/catalyst incurred in connection with operation of MPC’s refineries, and excludes planned turnaround and depreciation and amortization expenses. | ||
Greenhouse Gas (GHG) Intensity measures how efficiently MPC operates its facilities and implements a business plan that promotes a less carbon-intensive future. GHG intensity is based on Scope 1 and Scope 2 GHG emissions divided by the manufacturing inputs processed at MPC’s petroleum refineries, renewable fuel refineries and natural gas processing and fractionation plants. | ||
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Process Safety Events Rate measures MPC’s ability to identify, understand and control certain process hazards. | ||
Designated Environmental Incidents measures MPC’s environmental performance through tracking Tier 3 and 4 incidents. | ||
Diversity, Equity & Inclusion measures MPC’s effectiveness toward reaching its five-year representation goals with respect to women and Black, Indigenous and People of Color (“BIPOC”). | ||
The performance levels for each metric were established in February 2021 by evaluating factors such as performance achieved in the prior year(s), anticipated challenges for 2021, and MPC's business plan and overall strategy. MPC’s Compensation Committee also reviews disclosed peer methodologies of similar metrics when evaluating the rigor of performance goals. The performance levels were set with threshold levels viewed as likely achievable, target levels viewed as challenging but achievable, and maximum levels viewed as extremely difficult to achieve.
MPC’s Compensation Committee has sole discretion under the 2021 ACB program to adjust performance metric levels and/or the final payout percentage to recognize instances where, due to unforeseen circumstances, the performance metrics results are not entirely indicative of overall company results. MPC’s Compensation Committee made no such adjustments to the 2021 performance metric levels or final payout percentages.
MPC’s Compensation Committee also has discretion under the 2021 ACB to increase (by no more than 15%) or decrease payouts to certain of our officers, including our NEOs, based upon its assessment of each individual’s performance and contributions; provided, that our CEO’s payout cannot be increased pursuant to this discretion. While MPC’s Compensation Committee determined that our NEOs’ contributions to the successful execution in 2021 of MPC’s business objectives and enhancement of MPC shareholder value were significant, it concluded that the high achievement of performance metrics under the 2021 ACB adequately reflected these contributions and determined to make no individual adjustments.
ACB Payouts for 2021
In February 2022, MPC's Compensation Committee certified the results under the performance metrics for the 2021 ACB program and, taking into consideration MPC's performance relative to the pre-established metrics and the Committee’s evaluation of each NEO’s contributions to the key achievements discussed above, awarded the following amounts under the ACB program to our participating NEOs for 2021:
| Name | 2021 Year-End Base Salary ($) | Bonus Target as a % of Base Salary | Target Bonus ($) | Final Award as a % of Target | Final Award ($) | ||||||||||||||||||||||||||||||||||||
| Hennigan | 1,600,000 | 160 | 2,560,000 | 173 | 4,416,300 | ||||||||||||||||||||||||||||||||||||
| Quaid | 575,000 | 70 | 402,500 | 173 | 694,400 | ||||||||||||||||||||||||||||||||||||
| Gagle | 700,000 | 80 | 560,000 | 173 | 966,100 | ||||||||||||||||||||||||||||||||||||
| Floerke | 560,000 | 70 | 392,000 | 173 | 676,200 | ||||||||||||||||||||||||||||||||||||
| Aydt | 500,000 | 70 | 350,000 | 173 | 603,800 | ||||||||||||||||||||||||||||||||||||
| Beall | 535,192 | 70 | 374,634 | 173 | 646,300 | ||||||||||||||||||||||||||||||||||||
As noted above in “Compensation Allocation,” under our omnibus agreement, we pay MPC a fixed amount in return for services provided by our NEOs. The amounts shown in this table will be paid to our NEOs by MPC.
Mr. Hennigan’s 2021 ACB target percentage was increased by 7% over his 2020 target percentage in recognition of his experience in the CEO role and based on a review of competitive market data for his role. Ms. Gagle’s 2021 ACB target percentage was increased by 14% over her 2020 target percentage based on the MPC Compensation Committee’s review of competitive market data for her role. Mr. Aydt’s 2021 ACB target percentage was increased by 17% over his 2020 target percentage in recognition of the additional responsibilities he assumed upon his promotion to Executive Vice President and Chief Commercial Officer in late 2020. Ms. Beall was eligible for a 2021 ACB payout due to her retirement eligibility; eligible earnings reflect her salary earned for the portion of 2021 during which she was employed.
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2021 Long-Term Incentive Compensation Program
MPC’s long-term incentive (“LTI”) compensation program is designed to promote achievement of MPC’s and our long-term business objectives by linking our NEOs’ compensation directly to long-term company and equity performance, thereby strengthening alignment between the interests of our NEOs, MPC’s shareholders and our unitholders.
Under MPC’s 2021 LTI program, MPC’s Compensation Committee awarded our NEOs MPC performance share units (“PSUs”) and MPC restricted stock units (“RSUs”). Our NEOs also were awarded MPLX phantom units by a committee of our Board comprised of the independent directors (the “MPLX Committee”) following a recommendation by MPC's Compensation Committee. For 2021, MPC’s Compensation Committee approved the following LTI mix and annual award amounts for our NEOs:
| MPC LTI AWARDS | MPLX LTI AWARDS | |||||||||||||
| 60% PSUs | 20% RSUs | 20% Phantom Units | ||||||||||||
MPC PSUs align our NEOs’ long-term compensation interests with MPC’s shareholders’ long-term investment interests by conditioning payout on the performance of MPC’s Total Shareholder Return (“TSR”) relative to that of MPC’s peers over a three-year period. Awards vest in full at the end of the performance period. | ||||||||||||||
MPC RSUs promote our NEOs’ ownership of MPC’s common stock, aid in retention and help our NEOs comply with MPC’s stock ownership guidelines. Awards generally vest ratably over three years. | ||||||||||||||
MPLX Phantom Units promote our NEOs’ ownership of our common units, strengthening alignment between our NEOs’ compensation interests and our unitholders’ investment interests, and help our NEOs comply with our unit ownership guidelines. Awards generally vest ratably over three years. | ||||||||||||||
| Name | 60% MPC PSUs (at target) ($) | 20% MPC RSUs ($) | 20% MPLX Phantom Units ($) | Total 2021 LTI Target ($) | ||||||||||||||||||||||
| Hennigan | 6,750,000 | 2,250,000 | 2,250,000 | 11,250,000 | ||||||||||||||||||||||
| Quaid | 480,000 | 160,000 | 160,000 | 800,000 | ||||||||||||||||||||||
| Gagle | 1,350,000 | 450,000 | 450,000 | 2,250,000 | ||||||||||||||||||||||
| Floerke | 660,000 | 220,000 | 220,000 | 1,100,000 | ||||||||||||||||||||||
| Aydt | 660,000 | 220,000 | 220,000 | 1,100,000 | ||||||||||||||||||||||
| Beall | 750,000 | 250,000 | 250,000 | 1,250,000 | ||||||||||||||||||||||
To mitigate the effects of share price volatility, the number of awards granted is determined on the basis of the average 30-calendar day closing price prior to the grant date. Mr. Hennigan’s LTI target was increased by 7% over his 2020 LTI target in recognition of his experience in his role and based on a review of competitive market data for his role. Ms. Gagle’s, Mr. Floerke’s and Ms. Beall’s LTI targets were increased by 13%, 10% and 25%, respectively, over their 2020 LTI targets based on a review of competitive market data for their respective roles. Mr. Aydt’s LTI target was increased by 83% over his 2020 LTI target in recognition of the additional responsibilities he assumed upon his promotion to Executive Vice President and Chief Commercial Officer in late 2020.
MPC Performance Units/PSUs (2019, 2020 and 2021)
MPC performance units/PSUs pay out based on MPC’s three-year TSR performance relative to the peer group shown in the following table. MPC’s Compensation Committee chose relative TSR as the metric that most closely aligns the interests of executives and MPC’s shareholders. Each performance unit granted in 2019 and 2020 has a target value of $1.00, and the actual payout can vary from $0.00 to $2.00 (0% to 200% of target) per performance unit. Each PSU granted in 2021 has a target value equal to the MPC common stock average 30-day closing price prior to the grant date, and the actual payout value is based on company performance (which can range from 0% to 200%) multiplied by MPC’s closing share price on the date MPC’s Compensation Committee certifies performance. MPC’s relative TSR performance percentile is determined for the specified measurement periods, with linear interpolation used for results between target levels, as shown below. To provide greater alignment with MPC’s shareholders, payout under all MPC performance units and PSUs is capped at 100% in measurement periods when MPC TSR is negative.
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| MPC TSR PAYOUT PERCENTAGE CALCULATION | |||||||||||||||||||||||
| Below Threshold | Threshold | Target | Maximum | ||||||||||||||||||||
| TSR Percentile | Below 30th | 30th | 50th | 100th (Highest) | |||||||||||||||||||
| Payout (% of Target) | 0% | 50% | 100% | 200% | |||||||||||||||||||
| TSR CALCULATION | |||||||||||||||||||||||
| (Ending Stock Price* - Beginning Stock Price*) + Cumulative Cash Dividends | |||||||||||||||||||||||
| Beginning Stock Price* | |||||||||||||||||||||||
| *Calculated as the average of each company’s closing stock price for the 20 trading days immediately preceding each applicable date. | |||||||||||||||||||||||
| 2019 PERFORMANCE UNITS | 2020 PERFORMANCE UNITS | 2021 PSUS | |||||||||||||||||||||
| Settlement | 25% in MPC common stock and 75% in cash | 25% in MPC common stock and 75% in cash | 100% in cash | ||||||||||||||||||||
| Performance Period | 1/1/2019 - 12/31/2021 | 1/1/2020 - 12/31/2022 | 1/1/2021 - 12/31/2023 | ||||||||||||||||||||
| Measurement Periods | First 12 months Second 12 months Third 12 months Entire 36-month period | First 12 months Second 12 months Third 12 months Entire 36-month period | Entire 36-month period | ||||||||||||||||||||
| Peer Group | BP p.l.c. Chevron Corporation Exxon Mobil Corporation HollyFrontier Corporation PBF Energy Inc. Phillips 66 Valero Energy Corporation S&P 500 Energy Index | BP p.l.c. Chevron Corporation CVR Energy, Inc. Delek US Holdings, Inc. Exxon Mobil Corporation HollyFrontier Corporation PBF Energy Inc. Phillips 66 Valero Energy Corporation S&P 500 Energy Index | BP p.l.c. Chevron Corporation CVR Energy, Inc. Delek US Holdings, Inc. Exxon Mobil Corporation HollyFrontier Corporation PBF Energy Inc. Phillips 66 Valero Energy Corporation Median of Compensation Reference Group S&P 500 Index Alerian MLP Index | ||||||||||||||||||||
In January 2022, MPC’s Compensation Committee certified the final TSR results for the MPC 2019 performance units as follows:
Actual TSR (%) | Position Relative to Peer Group | Percentile Ranking (%) | TSR Payout Percentage (% of Target) | |||||||||||||||||
| TSR Measurement Period | ||||||||||||||||||||
| 1/1/2019–12/31/2019 | 3.16 | 4th of 9 | 62.50 | 125.00 | ||||||||||||||||
| 1/1/2020–12/31/2020 | -26.97 | 2nd of 9 | 87.50 | 100.00 | * | |||||||||||||||
| 1/1/2021–12/31/2021 | 57.67 | 2nd of 9 | 87.50 | 175.00 | ||||||||||||||||
| 1/1/2019–12/31/2021 | 16.03 | 2nd of 9 | 87.50 | 175.00 | ||||||||||||||||
| Average: | 143.75 | |||||||||||||||||||
* Although MPC’s performance percentile ranking of 87.50% relative to its peers for the January 1, 2020, through December 31, 2020, measurement period would have resulted in a payout percentage higher than 100%, payout is capped at 100% in measurement periods when TSR is negative. | ||||||||||||||||||||
The average payout above was applied to each participating NEO’s target award value as follows:
| Hennigan | Quaid | Gagle | Floerke | Aydt | Beall | |||||||||||||||
MPC 2019 Performance Units Granted (#) | 1,480,000 | 320,000 | 720,000 | 400,000 | 240,000 | 400,000 | ||||||||||||||
| Payout ($) | 2,127,500 | 460,000 | 1,035,000 | 575,000 | 345,000 | 575,000 | ||||||||||||||
MPC performance units and PSUs granted in 2020 and 2021 to our current NEOs remain outstanding. See the “2021 Grants of Plan-Based Awards” and “Outstanding Equity Awards at 2021 Fiscal Year-End” tables below for additional information about these awards.
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MPLX Performance Units (2019 and 2020; discontinued for 2021)
MPLX performance units were awarded to our NEOs in 2019 and 2020 as part of MPC’s LTI compensation program. Due to MPC’s restructuring of its LTI compensation program in 2021, new MPLX performance units are no longer awarded as part of the LTI mix. MPLX performance units awarded in 2019 and 2020 pay out based 50% on our total unitholder return (“TUR”) performance relative to a peer group of midstream companies and 50% on distributable cash flow (“DCF”) attributable to MPLX, measured over a three-year performance cycle. Each MPLX performance unit has a target value of $1.00, and the actual payout can vary from $0.00 to $2.00 (0% to 200% of target) per performance unit.
Total Unitholder Return (50% of MPLX Performance Unit Payout)
Our relative TUR performance percentile is determined for each of four measurement periods, with linear interpolation used for results between target levels, as follows:
| MPLX TUR PAYOUT PERCENTAGE CALCULATION | ||||||||||||||||||||||||||
| Below Threshold | Threshold | Target | Maximum | |||||||||||||||||||||||
| TUR Percentile | Below 30th | 30th | 50th | 100th (Highest) | ||||||||||||||||||||||
| Payout (% of Target) | 0% | 50% | 100% | 200% | ||||||||||||||||||||||
| TUR CALCULATION | ||||||||||||||||||||||||||
| (Ending Unit Price* - Beginning Unit Price*) + Cumulative Cash Distributions | ||||||||||||||||||||||||||
| Beginning Unit Price* | ||||||||||||||||||||||||||
| *Calculated as the average of each company’s closing unit price for the 20 trading days immediately preceding each applicable date. | ||||||||||||||||||||||||||
| 2019 PERFORMANCE UNITS | 2020 PERFORMANCE UNITS | |||||||||||||||||||||||||
| Settlement | 25% in MPLX common units and 75% in cash | 25% in MPLX common units and 75% in cash | ||||||||||||||||||||||||
| Performance Period | 1/1/2019 - 12/31/2021 | 1/1/2020 - 12/31/2022 | ||||||||||||||||||||||||
| Measurement Periods | First 12 months Second 12 months Third 12 months Entire 36-month period | First 12 months Second 12 months Third 12 months Entire 36-month period | ||||||||||||||||||||||||
| Peer Group | Andeavor Logistics LP* Buckeye Partners, L.P.* Enterprise Products Partners L.P. Magellan Midstream Partners, L.P. Phillips 66 Partners LP Plains All American Pipeline, L.P. Valero Energy Partners LP* Western Gas Partners, LP * Removed effective January 1, 2019 due to industry consolidation. | Ten companies in the Alerian MLP Index with the highest market capitalization as determined on the last day of each measurement period. For the 1/1/2020–12/31/2020 measurement period, these were: | ||||||||||||||||||||||||
| Cheniere Energy Partners LP DCP Midstream LP Enable Midstream Partners, LP Energy Transfer LP Enterprise Products Partners L.P. | Magellan Midstream Partners, L.P. Phillips 66 Partners LP Plains All American Pipeline, L.P. Shell Midstream Partners, L.P. Western Midstream Partners, LP | |||||||||||||||||||||||||
| For the 1/1/2021-12/31/2021 measurement period, the peer group was revised per the methodology above to remove Enable Midstream Partners, LP and add EnLink Midstream LLC. | ||||||||||||||||||||||||||
In January 2022, the MPLX Committee certified the final relative TUR results for the 2019 MPLX performance units as follows ($ in millions):
| Actual TUR (%) | Percentile Ranking (%) | TUR Payout Percentage (% of Target) | |||||||||||||||
| TUR Measurement Period | Position | ||||||||||||||||
| 1/1/2019–12/31/2019 | -13.83 | 5th of 6 | 20.00 | — | |||||||||||||
| 1/1/2020–12/31/2020 | 0.17 | 1st of 6 | 100.00 | 200.00 | |||||||||||||
| 1/1/2021–12/31/2021 | 43.72 | 2nd of 6 | 80.00 | 160.00 | |||||||||||||
| 1/1/2019–12/31/2021 | 16.71 | 1st of 6 | 100.00 | 200.00 | |||||||||||||
| Average: | 140.00 | ||||||||||||||||
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Distributable Cash Flow (50% of MPLX Performance Unit Payout)
DCF attributable to MPLX is measured for each year of a three-year performance cycle, with each year’s target based on our annual business plan as approved by our Board. Our DCF metric threshold, target and maximum levels are calculated as 90%, 100% and 105%, respectively, of the annual business plan DCF target. Linear interpolation is used for results between target levels.
In January 2022, the MPLX Committee certified the final relative DCF results for the 2019 MPLX performance units as follows ($ in millions):
| DCF Performance Period | Below Threshold (No Payout) | Threshold (50% Payout) | Target (100% Payout) | Maximum (200% Payout) | Actual DCF Attributable to MPLX | DCF Payout Percentage (% of Target) | ||||||||||||||
| 1/1/2019–12/31/2019 | Below $3,797 | $3,797 | $4,219 | $4,430 | $4,100 | 85.90 | ||||||||||||||
| 1/1/2020–12/31/2020 | Below $3,775 | $3,775 | $4,194 | $4,404 | $4,327 | 163.42 | ||||||||||||||
| 1/1/2021–12/31/2021 | Below $3,757 | $3,757 | $4,174 | $4,383 | $4,785 | 200.00 | ||||||||||||||
| Average: | 149.77 | |||||||||||||||||||
2019 MPLX Performance Unit Payouts
The average TUR payout percentage and the average DCF payout percentage shown above were averaged (144.89%) and applied to each NEO’s target award value as follows:
| Hennigan | Quaid | Gagle | Floerke | Aydt | Beall | |||||||||||||||
MPLX 2019 Performance Units Granted (#) | 370,000 | 80,000 | 180,000 | 100,000 | 60,000 | 100,000 | ||||||||||||||
| Payout ($) | 536,093 | 115,912 | 260,802 | 144,890 | 86,934 | 144,890 | ||||||||||||||
MPLX performance units granted in 2020 to our current NEOs remain outstanding. See the “2021 Grants of Plan-Based Awards” and “Outstanding Equity Awards at 2021 Fiscal Year-End” tables below for additional information about these awards.
MPC Synergy Performance Units
In January 2019, MPC’s Compensation Committee awarded our NEOs synergy performance units under a performance unit incentive program designed to promote MPC’s realization (or “capture”) of annual run-rate synergies in connection with the integration of Andeavor, which MPC acquired on October 1, 2018. The MPC synergy performance units were payable in cash upon the achievement of the following performance targets during each applicable performance period, with the payout for performance between levels determined using linear interpolation.
| OCTOBER 1, 2018 THROUGH DECEMBER 31, 2019 | JANUARY 1, 2020 THROUGH DECEMBER 31, 2020 | JANUARY 1, 2021 THROUGH DECEMBER 31, 2021 | ||||||||||||||||||
| Performance Level | Synergy Capture Performance | Payout Percentage | Synergy Capture Performance | Payout Percentage | Synergy Capture Performance | Payout Percentage | ||||||||||||||
| Maximum | $960 million | 200% | $1,420 million | 200% | $2,000 million | 200% | ||||||||||||||
| Target | $480 million | 100% | $710 million | 100% | $1,000 million | 100% | ||||||||||||||
| Threshold | $240 million | 50% | $355 million | 50% | $500 million | 50% | ||||||||||||||
| Below threshold | Below $240 million | 0% | Below $355 million | 0% | Below $500 million | 0% | ||||||||||||||
The MPC synergy performance units generally vested and were payable following completion of each performance period. Earlier vesting could occur in the event of a participant’s death or termination of employment, a change in control or if the captured synergies reach $2.0 billion prior to the completion of the final performance period. Each MPC synergy performance unit had a target value of $1.00, and the actual payout could vary from $0.00 to $2.00 (0% to 200% of target) per synergy performance unit.
In January 2022, MPC’s Compensation Committee certified the final synergy capture performance for the January 1, 2021, through December 31, 2021, performance period at $1,524 million, resulting in an initial payout percentage of 152%. However, taking into consideration the increasing challenge of identifying synergies that are directly attributable to the integration, particularly in light of MPC’s company-wide organizational and restructuring changes in 2020 and sale of the Speedway business in 2021, MPC’s Compensation Committee exercised its authority under
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the program and reduced the payout percentage for the 2021 performance period from 152% to 0%, resulting in no payouts to our NEOs under this program for the 2021 performance period:
| Hennigan | Quaid | Gagle | Floerke | Aydt | Beall | ||||||||||||||||||
| Target Number of MPC Synergy Performance Units for 2021 | 583,334 | 116,667 | 266,667 | 166,667 | 100,000 | 152,779 | * | ||||||||||||||||
| Payout ($) | — | — | — | — | — | — | |||||||||||||||||
| * A prorated portion of units granted to Ms. Beall was forfeited based on her retirement from MPC and all affiliated entities, including us, effective November 30, 2021. | |||||||||||||||||||||||
As noted above in “Compensation Allocation,” under our omnibus agreement, we pay MPC a fixed amount in return for services provided by our NEOs. All amounts previously paid under this program were paid to our NEOs by MPC.
As 2021 was the final performance period for this program, no synergy performance units remain outstanding, and this program has concluded.
OTHER BENEFITS
We do not sponsor any benefit plans, programs or policies such as healthcare, life insurance, income protection or retirement benefits for our NEOs, and we do not provide perquisites. However, those types of benefits are generally provided to our NEOs by MPC. MPC makes all determinations with respect to such benefits without input from our Board. MPC bears the full cost of these programs, and no portion is charged back to us. We have summarized the material elements of these programs below.
Health and Welfare Benefits
Our NEOs are generally eligible to participate in MPC’s market-competitive health and life insurance plans, long-term and short-term disability programs.
Retirement Benefits
Retirement benefits provided to our NEOs are designed by MPC to be consistent in value and aligned with benefits offered by the other companies with which MPC competes for talent. Benefits under MPC’s qualified and nonqualified plans are described in more detail in “Post-Employment Benefits for 2021” and “2021 Nonqualified Deferred Compensation.”
Severance Benefits
We and MPC maintain change in control plans designed to (i) preserve executives’ economic motivation to consider a business combination that might result in job loss and (ii) compete effectively in attracting and retaining executives in an industry that features frequent mergers, acquisitions and divestitures. Our change in control benefits are described further in “Potential Payments upon Termination or Change in Control.”
Limited Perquisites
Our NEOs receive limited perquisites, which are consistent with those offered by MPC’s peer group companies.
| Tax and Financial Planning Services | ||
MPC generally reimburses our NEOs for certain tax, estate and financial planning services up to $15,000 per year while serving as an executive and $3,000 in the year following retirement or death. | ||
| Health and Well-being | ||
Under MPC’s enhanced annual physical health program, our senior management, including our NEOs, are eligible for a comprehensive physical (generally in the form of a one-day appointment), with procedures similar to those available to all other employees under MPC’s health program. | ||
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| Use of Corporate Aircraft | ||
| The primary use of MPC’s corporate aircraft is for business purposes. MPC’s Board also has authorized Mr. Hennigan’s personal use of MPC’s corporate aircraft in the interest of his safety and security as its CEO. Certain other executives may be allowed limited personal use of MPC’s corporate aircraft, including for commuting purposes, and occasionally, spouses or other guests may accompany executive officers on corporate aircraft when space is available on business-related flights. All such personal use must be authorized by MPC’s CEO. The cost of any such travel that does not meet the Internal Revenue Service standard for business use is imputed as income to the executive officer. | ||
Additionally, MPC entered into an aircraft time sharing agreement with Mr. Hennigan, effective January 1, 2021, pursuant to which he may elect to use MPC’s corporate aircraft for transportation and personal use from time to time on a time sharing basis and pay MPC for such use pursuant to the terms of the agreement. The agreement was approved by MPC’s Corporate Governance and Nominating Committee and is reviewed on an annual basis consistent with MPC’s Related Person Transactions Policy. A copy of the aircraft time sharing agreement was filed as an exhibit to MPC’s Annual Report on Form 10-K for the year ended December 31, 2020. | ||
| Safety and Security | ||
| Given the significant public profile of MPC’s and our CEO and the publicity given to those in MPC’s industry, MPC’s Board has authorized certain limited security benefits to the CEO, including the maintenance, operation and monitoring of enhanced security systems. These benefits are monitored by MPC’s Compensation Committee and are taxable income to our CEO. | ||
Reportable values for these benefits and perquisites, based on the incremental costs to MPC, are included in the “All Other Compensation” column of the “2021 Summary Compensation Table.”
COMPENSATION GOVERNANCE
Unit Ownership Guidelines
Our unit ownership guidelines align our executive officers’ long-term interests with those of our unitholders. These guidelines require the executive officers in the positions shown below to retain MPLX common units with a value at least equal to a target multiple of their annualized base salary. The targeted multiples vary depending upon the executive’s position and responsibilities:
| Position | Multiple of Base Salary | ||||
CEO | 2x | ||||
| MPC Executive Vice President (CEO Direct Report) | 1x | ||||
| MPLX Executive Vice President (CEO Direct Report) MPC Senior Vice President (CEO Direct Report) | .75x | ||||
| All Other Executives (not reporting to the CEO) | .50x | ||||
Executives have five years following an increase in his or her applicable unit ownership guideline to achieve the applicable target multiple. Any executive who does not achieve the unit ownership guideline within this five-year window must hold all equity we grant until the applicable ownership guideline has been achieved. Our current NEOs meet these guidelines.
Prohibition on Hedging and Pledging
Under our policy on trading of securities, none of our directors, officers (including our NEOs) or certain MPC employees designated under the policy may purchase or sell any financial instrument, including but not limited to put or call options, the price of which is affected in whole or in part by changes in the price of our securities, unless such financial instrument was issued by us to such director, officer or covered employee. Further, no director, officer or covered employee may participate in any hedging transaction related to our securities. This policy ensures that our directors, officers and covered employees bear the full risk of MPLX common unit ownership.
Recoupment/Clawback Policy
MPC’s ACB and LTI programs provide for recoupment in the case of certain forfeiture events. In addition, our incentive compensation plans provide that all awards granted thereunder will be subject to clawback or recoupment in the case of certain forfeiture events. If the SEC or our Audit Committee requires us to prepare a material accounting restatement due to noncompliance with any financial reporting requirement under applicable securities
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laws as a result of misconduct, the Audit Committee may determine that a forfeiture event has occurred based on an assessment of whether an executive officer: (i) knowingly engaged in misconduct; (ii) was grossly negligent with respect to misconduct; (iii) knowingly failed or was grossly negligent in failing to prevent misconduct; or (iv) engaged in fraud, embezzlement or other similar misconduct materially harmful to us.
If it determines that a forfeiture event has occurred, MPC’s Compensation Committee may require reimbursement of any portion of an executive officer’s bonus from the ACB program that would not have been earned had the forfeiture event not occurred. Payments made in settlement of performance units may be recouped if the forfeiture event occurred while the executive officer was employed, or within three years after termination of employment. In addition, the executive’s unexercised and unvested equity awards would be subject to immediate forfeiture.
These recoupment provisions are in addition to any clawback provisions under Section 304 of the Sarbanes-Oxley Act of 2002, the Dodd-Frank Wall Street Reform and Consumer Protection Act, NYSE listing standards and other applicable law.
Compensation Risk Assessment
The independent members of our Board regularly review our policies and practices in compensating our service providers (including both executive officers and non-executives, if any) as they relate to our risk management profile. At the most recent review of our compensation program, our independent directors concluded that any risks arising from our compensation policies and practices were not reasonably likely to have a material adverse effect on our financial statements.
Compensation Committee Interlocks and Insider Participation
Because we are a limited partnership, we are not required to have a compensation committee. Compensation matters are determined by a committee of our Board comprised of the independent directors (the “MPLX Committee”), who for 2021 were Messrs. Helms, Peiffer, Sandman, Semple, Stice, Surma and Beatty (retired effective April 20, 2021). No member of the MPLX Committee was at any time during 2021 an officer or employee of MPLX or had any relationship with us requiring disclosure under Item 404 of Regulation S-K of the Exchange Act. Mr. Semple previously served as our Vice Chairman from December 2015 until his retirement in October 2016. Mr. Peiffer previously served as our President from 2012 until his retirement in 2014. See “Director Independence” in Item 10. Directors, Executive Officers and Corporate Governance for more information about our independent directors. Our Chairman, President and CEO, Mr. Hennigan, who is also an executive officer and director of MPC, provides input to the MPLX Committee on compensation matters. During 2021, none of our other executive officers served on the board of directors or compensation committee of any other entity that has an executive officer serving as a member of the MPLX Committee or the Board.
COMPENSATION COMMITTEE REPORT
Our independent directors have reviewed and discussed the Compensation Discussion and Analysis for 2021 with management and, based on such review and discussions, recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2021.
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
Frank M. Semple
J. Michael Stice
John P. Surma
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EXECUTIVE COMPENSATION TABLES
2021 SUMMARY COMPENSATION TABLE
The following table provides information regarding compensation for our 2021 NEOs for the years shown:
| Name and Principal Position | Salary | Bonus | Stock Awards | Option Awards | Non-Equity Incentive Plan Compensation | Change in Pension Value and Nonqualified Deferred Compensation Earnings | All Other Compensation | Total | |||||||||||||||||||||
| Year | ($) | ($) | ($) | ($) | ($) | ($) | ($) | ($) | |||||||||||||||||||||
Michael J. Hennigan Chairman, President and CEO | 2021 | 1,600,000 | — | 14,186,189 | — | 4,416,300 | 450,102 | 532,615 | 21,185,206 | ||||||||||||||||||||
| 2020 | 1,187,500 | — | 8,988,339 | 1,104,000 | 3,079,333 | 440,104 | 343,538 | 15,142,814 | |||||||||||||||||||||
| 2019 | 954,167 | — | 2,215,393 | 888,005 | 3,166,666 | 245,801 | 186,835 | 7,656,867 | |||||||||||||||||||||
John J. Quaid Executive Vice President and CFO | 2021 | 558,333 | — | 1,008,821 | — | 694,400 | 89,216 | 81,896 | 2,432,666 | ||||||||||||||||||||
Suzanne Gagle General Counsel | 2021 | 700,000 | — | 2,837,299 | — | 966,100 | 103,731 | 137,789 | 4,744,919 | ||||||||||||||||||||
| 2020 | 643,750 | — | 1,342,778 | 480,000 | 776,668 | 393,800 | 145,471 | 3,782,467 | |||||||||||||||||||||
| 2019 | 612,500 | — | 1,077,758 | 432,007 | 1,283,332 | 436,098 | 107,178 | 3,948,873 | |||||||||||||||||||||
Gregory S. Floerke Executive Vice President and Chief Operating Officer | 2021 | 560,000 | — | 1,387,178 | — | 676,200 | 109,955 | 105,058 | 2,838,391 | ||||||||||||||||||||
| 2020 | 545,000 | — | 671,413 | 240,000 | 574,667 | 161,979 | 114,411 | 2,307,470 | |||||||||||||||||||||
| 2019 | 536,250 | — | 598,772 | 240,009 | 953,332 | 125,985 | 87,453 | 2,541,801 | |||||||||||||||||||||
Timothy J. Aydt Executive Vice President and Chief Commercial Officer | 2021 | 475,000 | 130,000 | 1,387,178 | — | 603,800 | 20,762 | 70,976 | 2,687,716 | ||||||||||||||||||||
| 2020 | 370,000 | — | 402,861 | 144,000 | 350,000 | 348,188 | 74,307 | 1,689,356 | |||||||||||||||||||||
Pamela K.M. Beall Former Executive Vice President and CFO | 2021 | 527,083 | — | 1,585,614 | — | 646,300 | 96,344 | 238,109 | 3,093,450 | ||||||||||||||||||||
| 2020 | 563,750 | — | 671,413 | 240,000 | 585,667 | 194,300 | 118,937 | 2,374,067 | |||||||||||||||||||||
| 2019 | 556,250 | — | 598,772 | 240,009 | 1,008,332 | 197,733 | 98,844 | 2,699,940 | |||||||||||||||||||||
Salary shows the actual amount earned during the year. See the base salary overview in the CD&A for additional information on base salaries for 2021.
Bonus reflects a one-time cash amount awarded by MPC’s Compensation Committee to Mr. Aydt in early 2021 in recognition of the significant responsibilities he assumed beginning in mid-2020 as part of MPC’s organizational restructuring process.
Stock Awards and Option Awards reflect the aggregate grant date fair value of LTI awarded in the applicable year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification 718, Compensation—Stock Compensation (“FASB ASC Topic 718”). MPC’s Compensation Committee awards LTIs to our NEOs based on intended target values, which reflect established compensation valuation methodologies that differ in some respects from the FASB ASC Topic 718 methodologies reflected in this table. See “2021 Long-Term Incentive Compensation Program” in the CD&A for additional information about the intended target values for the 2021 LTI awards to our NEOs. For assumptions used to determine the values of these awards as shown in this table, see Note 27 to MPC’s financial statements included in its Annual Reports on Form 10-K for the years ended December 31, 2021 and 2020, the "Grant Date Fair Value” note accompanying the “2021 Grants of Plan-Based Awards” table below, and Item 8. Financial Statements and Supplementary Data, Note 21 of our Annual Report on Form 10-K for the year ended December 31, 2020.
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MPC PSUs granted in 2021 are included in the Stock Awards column for 2021. Their maximum value at grant date, assuming the highest level of performance achieved, is:
| Hennigan | Quaid | Gagle | Floerke | Aydt | Beall | |||||||||||||||
MPC 2021 Performance Units ($) | 18,739,436 | 1,332,596 | 3,747,944 | 1,832,425 | 1,832,425 | 2,082,269 | ||||||||||||||
Non-Equity Incentive Plan Compensation reflects the total ACB award earned for the year indicated, paid the following year. See “2021 Annual Cash Bonus Program” in the CD&A for additional information on payouts under this program for 2021. Amounts shown for 2019 and 2020 also include payouts under the synergy performance units for the performance periods from October 1, 2018, through December 31, 2019, and January 1, 2020, through December 31, 2020, respectively.
Change in Pension Value and Nonqualified Deferred Compensation Earnings reflects the annual change in actuarial present value of accumulated benefits under the MPC retirement plans. See “Post-Employment Benefits for 2021” for more information about the defined benefit plans and the assumptions used to calculate these amounts. No deferred compensation earnings are reported as our nonqualified deferred compensation plans do not provide above-market or preferential earnings.
All Other Compensation aggregates MPC’s contributions to defined contribution plans and the limited perquisites MPC offers to our NEOs, which are described in more detail in the perquisites overview above beginning on page 159.
| Name | Personal Use of Company Aircraft ($) | Company Physicals ($) | Tax and Financial Planning ($) | Security ($) | Company Contributions to Defined Contribution Plans ($) | Other ($) | Total All Other Compensation ($) | |||||||||||||||||||||||||||||||||||||
| Hennigan | 165,754 | 4,016 | 30,000 | 4,356 | 328,489 | — | 532,615 | |||||||||||||||||||||||||||||||||||||
| Quaid | — | 4,016 | 12,020 | — | 65,860 | — | 81,896 | |||||||||||||||||||||||||||||||||||||
| Gagle | — | 4,016 | 9,064 | — | 124,659 | 50 | 137,789 | |||||||||||||||||||||||||||||||||||||
| Floerke | — | 4,016 | 3,100 | — | 97,942 | — | 105,058 | |||||||||||||||||||||||||||||||||||||
| Aydt | — | 4,016 | — | — | 66,960 | — | 70,976 | |||||||||||||||||||||||||||||||||||||
| Beall | — | 4,016 | 7,380 | — | 99,794 | 126,919 | 238,109 | |||||||||||||||||||||||||||||||||||||
“Personal Use of Company Aircraft” reflects MPC’s aggregate incremental cost of personal use of corporate aircraft by our NEOs, their spouses or other guests for 2021. Such costs reported above for 2021 were primarily attributable to commuting flights between Mr. Hennigan’s residence in Findlay, Ohio, our headquarters, and another residence. MPC determines the incremental cost for personal use of its aircraft based on the variable costs to operate the aircraft, but excluding fixed costs that do not change based on usage, such as pilot compensation, the purchase and lease of aircraft and maintenance not related to travel. MPC believes this method provides a reasonable estimate of its incremental cost. No income tax assistance or gross-ups are provided for personal use of corporate aircraft. See “Other Benefits” in the CD&A for additional information regarding personal use of MPC aircraft by our executives.
“Company Contributions to Defined Contribution Plans” reflect MPC’s contributions under its tax-qualified retirement plans and related nonqualified deferred compensation plans. See “Post-Employment Benefits for 2021” and “2021 Nonqualified Deferred Compensation” for more information.
“Other” for Ms. Beall includes $100,071 for her vested but unused vacation benefit paid upon her retirement, $16,848 in total compensation (consisting of $7,582 cash and $9,266 aggregate grant date fair value of MPLX phantom units, calculated in accordance with FASB ASC Topic 718) for her service as a non-employee director on our Board, prorated for the period from December 1, 2021, following her retirement, through December 31, 2021, and a $10,000 charitable contribution to an institution of higher learning under MPC’s matching gifts program.
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2021 GRANTS OF PLAN-BASED AWARDS
The following table provides information regarding MPC plan-based awards, including cash-based incentive awards and equity-based awards, granted by MPC’s Compensation Committee to our NEOs in 2021, as well as all MPLX plan-based awards granted by the MPLX Committee to our NEOs in 2021.
| Name | Type of Award | Grant Date | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Stock Awards: Number of Shares of Stock or Units (#) | Grant Date Fair Value of Stock and Option Awards ($) | ||||||||||||||||||||||||||
| Threshold ($) | Target ($) | Maximum ($) | Threshold ($) | Target ($) | Maximum ($) | |||||||||||||||||||||||||||
| Hennigan | MPC Annual Cash Bonus | — | 2,560,000 | 5,120,000 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 44,353 | 2,488,203 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 66,529 | 133,058 | 266,116 | 9,369,718 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 93,168 | 2,328,268 | |||||||||||||||||||||||||||||
| Quaid | MPC Annual Cash Bonus | — | 402,500 | 805,000 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 3,154 | 176,939 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 4,731 | 9,462 | 18,924 | 666,298 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 6,626 | 165,584 | |||||||||||||||||||||||||||||
| Gagle | MPC Annual Cash Bonus | — | 560,000 | 1,120,000 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 8,871 | 497,663 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 13,306 | 26,612 | 53,224 | 1,873,972 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 18,634 | 465,664 | |||||||||||||||||||||||||||||
| Floerke | MPC Annual Cash Bonus | — | 392,000 | 784,000 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 4,337 | 243,306 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 6,506 | 13,011 | 26,022 | 916,213 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 9,110 | 227,659 | |||||||||||||||||||||||||||||
| Aydt | MPC Annual Cash Bonus | — | 350,000 | 700,000 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 4,337 | 243,306 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 6,506 | 13,011 | 26,022 | 916,213 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 9,110 | 227,659 | |||||||||||||||||||||||||||||
| Beall | MPC Annual Cash Bonus | — | 374,634 | 749,268 | ||||||||||||||||||||||||||||
| MPC RSUs | 3/1/2021 | 4,929 | 276,517 | |||||||||||||||||||||||||||||
| MPC PSUs | 3/1/2021 | 7,393 | 14,785 | 29,570 | 1,041,135 | |||||||||||||||||||||||||||
| MPLX Phantom Units | 3/1/2021 | 10,352 | 258,696 | |||||||||||||||||||||||||||||
| MPLX Phantom Units | 12/9/2021 | 320 | 9,266 | |||||||||||||||||||||||||||||
Approval Dates. The MPC awards granted on March 1, 2021, were approved by MPC’s Compensation Committee on January 29, 2021 (for Mr. Hennigan) and February 24, 2021 (for the other NEOs). The MPLX awards granted on March 1, 2021, were approved by the MPLX Committee on February 25, 2021. The MPLX awards granted to Ms. Beall on December 9, 2021, were made pursuant to MPLX’s director compensation program for non-employee directors in effect for 2021, which was approved by our Board on October 31, 2018.
MPC RSUs generally vest in equal installments on the first, second and third anniversaries of the grant date. Unvested RSUs accrue dividend equivalents, which are paid on the scheduled vesting dates. Holders of unvested RSUs do not have voting rights.
MPC PSUs generally vest following a 36-month performance period and are settled 100% in cash. Unvested PSUs do not accrue dividends or dividend equivalents and do not have voting rights. The target PSUs shown reflect the target dollar value of each award divided by the MPC common stock average 30-day closing price prior to the grant date. The threshold, which is the minimum possible payout, is achieved when the relative TSR percentile achieved is 30th, resulting in a payout percentage of 50%. Performance below this threshold would result in a payout of 0%. The maximum payout is 200% of target.
MPLX Phantom Units generally vest in equal installments on the first, second and third anniversaries of the grant date and are settled in MPLX common units. Distribution equivalents accrue on the phantom unit awards and are paid on the scheduled vesting dates. Holders of unvested phantom units have no voting rights.
Grant Date Fair Value reflects the total grant date fair value of each equity award calculated in accordance with FASB ASC Topic 718. The MPC RSU values are based on the MPC common stock
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closing price of $56.10 on the grant date, or the prior business day if the grant date did not fall on a business day. The MPC PSUs value was $70.4183 per unit, using a Monte Carlo valuation model. The MPLX phantom unit values are based on the MPLX common unit closing price on the grant date, or the prior business day if the grant date did not fall on a business day, which was $24.99 and $28.96 for the March 1, 2021, and December 9, 2021, awards, respectively.
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OUTSTANDING EQUITY AWARDS AT 2021 FISCAL YEAR-END
The following table provides information regarding the outstanding equity awards held by our NEOs as of December 31, 2021.
| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||
| Name | Grant Date | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options (#) Unexercisable | Option Exercise Price ($) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested ($) | |||||||||||||||||||||||
| Hennigan | 3/1/2018 | 30,225 | — | 64.79 | 3/1/2028 | MPC | ||||||||||||||||||||||||||
| 3/1/2019 | 61,925 | — | 62.68 | 3/1/2029 | 250,163 | 16,007,930 | 1,973,058 | 20,708,763 | ||||||||||||||||||||||||
| 3/1/2020 | 37,666 | 75,333 | 47.73 | 3/1/2030 | MPLX | |||||||||||||||||||||||||||
| 129,816 | 75,333 | 112,016 | 3,314,553 | 460,000 | 920,000 | |||||||||||||||||||||||||||
| Quaid | 3/1/2015 | 12,594 | — | 50.89 | 3/1/2025 | |||||||||||||||||||||||||||
| 3/1/2016 | 17,653 | — | 34.63 | 3/1/2026 | ||||||||||||||||||||||||||||
| 3/1/2017 | 15,731 | — | 50.99 | 3/1/2027 | ||||||||||||||||||||||||||||
| 3/1/2018 | 9,672 | — | 64.79 | 3/1/2028 | MPC | |||||||||||||||||||||||||||
| 3/1/2019 | 13,390 | — | 62.68 | 3/1/2029 | 5,324 | 340,683 | 329,462 | 1,850,947 | ||||||||||||||||||||||||
| 3/1/2020 | 6,550 | 13,102 | 47.73 | 3/1/2030 | MPLX | |||||||||||||||||||||||||||
| 75,590 | 13,102 | 10,056 | 297,557 | 80,000 | 160,000 | |||||||||||||||||||||||||||
| Gagle | 4/2/2012 | 4,210 | — | 21.72 | 4/2/2022 | |||||||||||||||||||||||||||
| 4/1/2013 | 2,370 | — | 44.92 | 4/1/2023 | ||||||||||||||||||||||||||||
| 4/1/2014 | 3,006 | — | 44.77 | 4/1/2024 | ||||||||||||||||||||||||||||
| 4/1/2015 | 4,120 | — | 50.88 | 4/1/2025 | ||||||||||||||||||||||||||||
| 3/1/2016 | 25,678 | — | 34.63 | 3/1/2026 | ||||||||||||||||||||||||||||
| 3/1/2017 | 26,967 | — | 50.99 | 3/1/2027 | ||||||||||||||||||||||||||||
| 3/1/2018 | 13,817 | — | 64.79 | 3/1/2028 | MPC | |||||||||||||||||||||||||||
| 3/1/2019 | 30,126 | — | 62.68 | 3/1/2029 | 13,829 | 884,918 | 826,612 | 5,005,804 | ||||||||||||||||||||||||
| 3/1/2020 | 16,376 | 32,754 | 47.73 | 3/1/2030 | MPLX | |||||||||||||||||||||||||||
| 126,670 | 32,754 | 26,254 | 776,856 | 200,000 | 400,000 | |||||||||||||||||||||||||||
| Floerke | 3/1/2017 | 4,495 | — | 50.99 | 3/1/2027 | |||||||||||||||||||||||||||
| 3/1/2018 | 8,636 | — | 64.79 | 3/1/2028 | MPC | |||||||||||||||||||||||||||
| 3/1/2019 | 16,737 | — | 62.68 | 3/1/2029 | 6,875 | 439,931 | 413,011 | 2,465,148 | ||||||||||||||||||||||||
| 3/1/2020 | 8,188 | 16,377 | 47.73 | 3/1/2030 | MPLX | |||||||||||||||||||||||||||
| 38,056 | 16,377 | 49,506 | 1,464,883 | 100,000 | 200,000 | |||||||||||||||||||||||||||
| Aydt | 4/1/2013 | 3,746 | — | 44.92 | 4/1/2023 | |||||||||||||||||||||||||||
| 4/1/2014 | 4,810 | — | 44.77 | 4/1/2024 | ||||||||||||||||||||||||||||
| 4/1/2015 | 6,556 | — | 50.88 | 4/1/2025 | ||||||||||||||||||||||||||||
| 4/1/2016 | 9,106 | — | 36.39 | 4/1/2026 | ||||||||||||||||||||||||||||
| 4/1/2017 | 7,589 | — | 49.94 | 4/1/2027 | ||||||||||||||||||||||||||||
| 4/1/2018 | 5,907 | — | 71.80 | 4/1/2028 | MPC | |||||||||||||||||||||||||||
| 3/1/2019 | 10,042 | — | 62.68 | 3/1/2029 | 5,821 | 372,486 | 253,011 | 2,145,148 | ||||||||||||||||||||||||
| 3/1/2020 | 4,913 | 9,826 | 47.73 | 3/1/2030 | MPLX | |||||||||||||||||||||||||||
| 52,669 | 9,826 | 11,387 | 336,941 | 60,000 | 120,000 | |||||||||||||||||||||||||||
| Beall | 3/1/2015 | 20,150 | — | 50.89 | 3/1/2025 | |||||||||||||||||||||||||||
| 3/1/2016 | 17,052 | — | 34.63 | 3/1/2026 | ||||||||||||||||||||||||||||
| 3/1/2017 | 4,776 | — | 50.99 | 11/30/2026 | ||||||||||||||||||||||||||||
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| Option Awards | Stock Awards | |||||||||||||||||||||||||||||||
| Name | Grant Date | Number of Securities Underlying Unexercised Options (#) Exercisable | Number of Securities Underlying Unexercised Options (#) Unexercisable | Option Exercise Price ($) | Option Expiration Date | Number of Shares or Units of Stock That Have Not Vested (#) | Market Value of Shares or Units of Stock That Have Not Vested ($) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested (#) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested ($) | |||||||||||||||||||||||
| 3/1/2018 | 8,636 | — | 64.79 | 11/30/2026 | MPC | |||||||||||||||||||||||||||
| 3/1/2019 | 16,737 | — | 62.68 | 11/30/2026 | 7,354 | 470,582 | 414,785 | 2,692,184 | ||||||||||||||||||||||||
| 3/1/2020 | 24,565 | — | 47.73 | 11/30/2026 | MPLX | |||||||||||||||||||||||||||
| 91,916 | — | 14,089 | 416,894 | 100,000 | 200,000 | |||||||||||||||||||||||||||
MPC Stock Options generally vest in equal installments on the first, second and third anniversaries of the grant date and expire 10 years after the grant date. The exercise price is generally equal to the closing price of our common stock on the grant date, or the prior business day if the grant date did not fall on a business day. Option holders do not have voting rights or receive dividends on the underlying stock. Stock options held by Ms. Beall expire upon the earlier of five years following her retirement and the existing expiration date applicable to each such option. No stock options have been granted to any NEO since 2020.
Unvested Shares and Units reflect the number of unvested MPC RSUs/shares of restricted stock and MPLX phantom units held on December 31, 2021. MPC RSUs/restricted stock and MPLX phantom units generally vest in equal installments on the first, second and third anniversaries of the grant date.
| MPC RSUs/Restricted Stock | MPLX LP Phantom Units | |||||||||||||||||||||||||
| Name | Grant Date | Number of Unvested Shares | Vesting Dates | Grant Date | Number of Unvested Units | Vesting Dates | ||||||||||||||||||||
| Hennigan | 3/1/2019 | 1,768 | 3/1/2022 | 3/1/2019 | 3,568 | 3/1/2022 | ||||||||||||||||||||
| 3/1/2020 | 10,281 | 3/1/2022, 3/1/2023 | 3/1/2020 | 15,280 | 3/1/2022, 3/1/2023 | |||||||||||||||||||||
| 3/17/2020 | 193,761 | 3/17/2022, 3/17/2023 | 3/1/2021 | 93,168 | 3/1/2022, 3/1/2023, 3/1/2024 | |||||||||||||||||||||
| 3/1/2021 | 44,353 | 3/1/2022, 3/1/2023, 3/1/2024 | 112,016 | |||||||||||||||||||||||
| 250,163 | ||||||||||||||||||||||||||
| Quaid | 3/1/2019 | 382 | 3/1/2022 | 3/1/2019 | 772 | 3/1/2022 | ||||||||||||||||||||
| 3/1/2020 | 1,788 | 3/1/2022, 3/1/2023 | 3/1/2020 | 2,658 | 3/1/2022, 3/1/2023 | |||||||||||||||||||||
| 3/1/2021 | 3,154 | 3/1/2022, 3/1/2023, 3/1/2024 | 3/1/2021 | 6,626 | 3/1/2022, 3/1/2023, 3/1/2024 | |||||||||||||||||||||
| 5,324 | 10,056 | |||||||||||||||||||||||||
| Gagle | 3/1/2019 | 849 | 3/1/2022 | 3/1/2019 | 1,735 | 3/1/2022 | ||||||||||||||||||||
| 3/1/2020 | 4,470 | 3/1/2022, 3/1/2023 | 3/1/2020 | 6,644 | 3/1/2022, 3/1/2023 | |||||||||||||||||||||
| 3/1/2021 | 8,510 | 3/1/2022, 3/1/2023, 3/1/2024 | 3/1/2021 | 17,875 | 3/1/2022, 3/1/2023, 3/1/2024 | |||||||||||||||||||||
| 13,829 | 26,254 | |||||||||||||||||||||||||
| Floerke | 3/1/2019 | 477 | 3/1/2022 | 12/18/2015 | 36,476 | Upon termination without cause | ||||||||||||||||||||
| 3/1/2020 | 2,236 | 3/1/2022, 3/1/2023 | 3/1/2019 | 965 | 3/1/2022 | |||||||||||||||||||||
| 3/1/2021 | 4,162 | 3/1/2022, 3/1/2023, 3/1/2024 | 3/1/2020 | 3,322 | 3/1/2022, 3/1/2023 | |||||||||||||||||||||
| 6,875 | 3/1/2021 | 8,743 | 3/1/2022, 3/1/2023, 3/1/2024 | |||||||||||||||||||||||
| 49,506 | ||||||||||||||||||||||||||
| Aydt | 3/1/2019 | 283 | 3/1/2022 | 3/1/2019 | 578 | 3/1/2022 | ||||||||||||||||||||
| 3/1/2020 | 1,342 | 3/1/2022, 3/1/2023 | 3/1/2020 | 1,994 | 3/1/2022, 3/1/2023 | |||||||||||||||||||||
| 3/1/2021 | 4,196 | 3/1/2022, 3/1/2023, 3/1/2024 | 3/1/2021 | 8,815 | 3/1/2022, 3/1/2023, 3/1/2024 | |||||||||||||||||||||
| 5,821 | 11,387 | |||||||||||||||||||||||||
| Beall | 3/1/2019 | 478 | 3/1/2022 | 3/1/2019 | 965 | 3/1/2022 | ||||||||||||||||||||
| 3/1/2020 | 2,146 | 6/1/2022 | 3/1/2020 | 3,188 | 6/1/2022 | |||||||||||||||||||||
| 3/1/2021 | 4,730 | 6/1/2022 | 3/1/2021 | 9,936 | 6/1/2022 | |||||||||||||||||||||
| 7,354 | 14,089 | |||||||||||||||||||||||||
Market Value of Unvested Shares and Units reflects the aggregate value of all shares of unvested MPC RSUs/restricted stock and MPLX phantom units held on December 31, 2021, using the MPC closing stock price of $63.99 and the MPLX closing unit price of $29.59 on that date.
Unvested Equity Incentive Plan Awards reflect the number of unvested MPC performance units/PSUs and MPLX performance units held on December 31, 2021. Performance units/PSUs generally vest following a 36-month performance period. No MPLX performance units have been granted to any NEO since 2020.
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| Name | MPC Performance Units | MPLX Performance Units | |||||||||||||||||||||
| Grant Date | Number of Unvested Units | Performance Cycle | Grant Date | Number of Unvested Units | Performance Cycle | ||||||||||||||||||
| Hennigan | 3/1/2020 | 1,840,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 460,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 133,058 | 1/1/2021 - 12/31/2023 | 460,000 | ||||||||||||||||||||
| 1,973,058 | |||||||||||||||||||||||
| Quaid | 3/1/2020 | 320,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 80,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 9,462 | 1/1/2021 - 12/31/2023 | 80,000 | ||||||||||||||||||||
| 329,462 | |||||||||||||||||||||||
| Gagle | 3/1/2020 | 800,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 200,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 26,612 | 1/1/2021 - 12/31/2023 | 200,000 | ||||||||||||||||||||
| 826,612 | |||||||||||||||||||||||
| Floerke | 3/1/2020 | 400,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 100,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 13,011 | 1/1/2021 - 12/31/2023 | 100,000 | ||||||||||||||||||||
| 413,011 | |||||||||||||||||||||||
| Aydt | 3/1/2020 | 240,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 60,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 13,011 | 1/1/2021 - 12/31/2023 | 60,000 | ||||||||||||||||||||
| 253,011 | |||||||||||||||||||||||
| Beall | 3/1/2020 | 400,000 | 1/1/2020 - 12/31/2022 | 3/1/2020 | 100,000 | 1/1/2020 - 12/31/2022 | |||||||||||||||||
| 3/1/2021 | 14,785 | 1/1/2021 - 12/31/2023 | 100,000 | ||||||||||||||||||||
| 414,785 | |||||||||||||||||||||||
Market Value of Unvested Equity Incentive Plan Awards reflects the aggregate value of all unvested MPC performance units/PSUs and MPLX performance units held on December 31, 2021. The values of the 2020 MPC performance units were calculated using an assumed payout of 200% per unit, which is the next higher performance achievement that exceeds the performance for these awards’ measurement period ended December 31, 2021. The values of the 2021 MPC PSUs were calculated using the MPC closing stock price of $63.99 on December 31, 2021, and an assumed payout of 200% per unit, which is the next higher performance achievement that exceeds the performance for these awards’ measurement period ended December 31, 2021. The values of the 2020 MPLX performance units were calculated using an assumed payout of 200% per unit, which is the next higher performance achievement that exceeds the performance for these awards’ measurement period ended December 31, 2021.
Nonforfeitability of Certain Awards. Pursuant to award agreement amendments made in 2019 for retention purposes (as further amended in December 2020 for administrative purposes), outstanding MPC stock options and restricted stock and MPLX phantom units granted to our NEOs in 2019 became nonforfeitable for tax purposes on December 28, 2020. Outstanding stock options held by Ms. Gagle and Mr. Aydt are nonforfeitable because each executive is retirement-eligible, having reached age 50 with at least 10 years of service with MPC. In addition, Ms. Gagle and Mr. Aydt are eligible for an Approved Separation, under which their outstanding 2021 MPC RSUs, MPC PSUs and MPLX phantom units would become nonforfeitable should they resign under certain conditions, as further discussed below under “Potential Payments Upon Termination or Change in Control—Approved Separation.” Pursuant to the terms of his promotion to the CEO role in March 2020, Mr. Hennigan’s 2020 awards of MPC stock options, RSUs and performance units and MPLX phantom units and performance units will become nonforfeitable on July 1, 2022.
When an award becomes nonforfeitable, certain taxes are immediately due. So that the participants do not have an out-of-pocket expense for these awards that have not yet distributed, the award is instead reduced to cover the tax obligation. These awards continue to be reflected in the tables above as they remain subject to distribution on their original vesting dates; however, the portions used to pay any associated taxes have been excluded from these tables and are instead included in the “Option Exercises and Stock Vested in 2021” table below.
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OPTION EXERCISES AND STOCK VESTED IN 2021
The following table provides information regarding MPC stock options exercised by our NEOs in 2021, as well as shares of MPC RSUs/restricted stock and MPLX phantom units vested in 2021.
| Option Awards | Stock/Unit Awards | ||||||||||||||||||||||||||||
| Name | Number of Shares Acquired on Exercise (#) | Value Realized on Exercise ($) | Number of Shares/Units Acquired on Vesting (#) | Value Realized on Vesting ($) | |||||||||||||||||||||||||
| Hennigan | MPC | — | — | 104,798 | 5,837,347 | ||||||||||||||||||||||||
| MPLX | 19,232 | 472,915 | |||||||||||||||||||||||||||
| Quaid | MPC | — | — | 1,599 | 89,507 | ||||||||||||||||||||||||
| MPLX | 2,742 | 67,426 | |||||||||||||||||||||||||||
| Gagle | MPC | 9,390 | 362,468 | 3,900 | 219,807 | ||||||||||||||||||||||||
| MPLX | 9,481 | 237,001 | |||||||||||||||||||||||||||
| Floerke | MPC | — | — | 2,056 | 115,827 | ||||||||||||||||||||||||
| MPLX | 5,284 | 131,802 | |||||||||||||||||||||||||||
| Aydt | MPC | 7,600 | 342,637 | 1,610 | 94,566 | ||||||||||||||||||||||||
| MPLX | 2,848 | 72,836 | |||||||||||||||||||||||||||
| Beall | MPC | 21,874 | 449,506 | 2,172 | 122,811 | ||||||||||||||||||||||||
| MPLX | 5,788 | 146,524 | |||||||||||||||||||||||||||
Value Realized on Exercise reflects the actual pre-tax gain realized by our NEOs upon exercise of stock options, which is the fair market value of the shares at exercise less the per share grant price.
Number of Shares/Units Acquired on Vesting includes the following numbers of shares/units used to pay the taxes associated with the vesting of certain awards held by the NEOs due to certain awards and award amendments, as discussed further under “Outstanding Equity Awards at 2021 Fiscal Year-End”: Ms. Gagle, 361 MPC RSUs/restricted stock and 759 MPLX phantom units; Mr. Floerke, 175 MPC RSUs/restricted stock and 367 MPLX phantom units; Mr. Aydt, 141 MPC RSUs/restricted stock and 295 MPLX phantom units; Ms. Beall, 289 MPC RSUs/restricted stock and 550 MPLX phantom units.
Value Realized on Vesting reflects the fair market value of the shares/units on the vesting date.
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POST-EMPLOYMENT BENEFITS FOR 2021
2021 Pension Benefits
MPC provides tax-qualified retirement benefits to its employees, including our NEOs, under the MPC Retirement Plan. MPC also provides unfunded nonqualified deferred compensation plan benefits to a select group of management or highly compensated employees, including our NEOs, under the MPC Excess Benefit Plan. The following table reflects the actuarial present value of accumulated benefits payable to each of our NEOs under the MPC Retirement Plan and the defined benefit portion of the MPC Excess Benefit Plan as of December 31, 2021. These values have been determined using actuarial assumptions consistent with those used in MPC’s financial statements.
| Name | Plan Name | Number of Years Credited Service (#) | Present Value of Accumulated Benefit ($) | Payments During Last Fiscal Year ($) | ||||||||||||||||
| Hennigan | MPC Retirement Plan | 4.58 | 133,511 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 4.58 | 1,281,184 | — | |||||||||||||||||
| Quaid | MPC Retirement Plan | 7.58 | 191,513 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 7.58 | 463,086 | — | |||||||||||||||||
| Gagle | MPC Retirement Plan | 28.67 | 1,225,577 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 28.67 | 919,086 | — | |||||||||||||||||
| Floerke | MPC Retirement Plan | 6.00 | 161,838 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 6.00 | 470,831 | — | |||||||||||||||||
| Aydt | MPC Retirement Plan | 36.58 | 1,870,368 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 36.58 | 1,145,793 | — | |||||||||||||||||
| Beall | MPC Retirement Plan | 19.58 | 952,701 | — | ||||||||||||||||
| MPC Excess Benefit Plan | 19.58 | 2,025,146 | — | |||||||||||||||||
Number of Years Credited Service shows the number of years the NEO has participated in each plan. Plan participation service used to calculate each participant’s benefit under the MPC Retirement Plan legacy final average pay formula (applicable to Ms. Gagle and Mr. Aydt only) was frozen as of December 31, 2009.
Present Value of Accumulated Benefit for the legacy benefit under the MPC Retirement Plan was calculated assuming a 90% lump sum election rate with a lump sum interest rate between 0.00% and 1.25% (based on anticipated year of retirement) and the RP-2000 mortality table, and a 10% annuity election rate with a discount rate of 2.90% and the Pri-2012 mortality table with generational mortality improvements in accordance with Scale MP-2021, both calculated assuming retirement at age 62 (or current age, if later).
The present value of accumulated benefits for the cash balance benefit under the MPC Retirement Plan was calculated assuming retirement at age 62 (or current age, if later), a discount rate of 2.90%, a cash balance interest credit rating of 3.0%, and the Pri-2012 mortality table with generational mortality improvements in accordance with Scale MP-2021. See "MPC Retirement Plan" below for more detail on the legacy and cash balance benefit formulas.
MPC Retirement Plan
In general, our employees participate in the MPC Retirement Plan, which is a tax-qualified defined benefit retirement plan primarily designed to provide participants with income after retirement. Participants in the plan become fully vested upon completing three years of vesting service. Normal retirement age under the plan is 65. The plan has both a “legacy” retirement benefit and a “cash balance” retirement benefit.
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Legacy Benefit
Prior to 2010, the monthly benefit was determined under the following legacy benefit formula.
| 1.6% | × | Monthly Final Average Pay | × | Years of Participation | |||||||||||||||||||||||||
| – | 1.33% | × | Monthly Estimated Primary Social Security Benefit | × | Years of Participation | ||||||||||||||||||||||||
| Legacy Monthly Benefit | |||||||||||||||||||||||||||||
This formula was amended effective January 1, 2010, to cease future accruals of additional participation years, and as applied to eligible NEOs, cease further compensation updates. No more than 37.5 participation years may be recognized under the formula. Eligible earnings include, but are not limited to, pay for hours worked, pay for allowed hours, military leave allowance, commissions, bonuses and elective deferrals to the MPC Thrift Plan. Age continues to be updated under the formula.
Under the legacy retirement benefit, a vested participant who is at least age 62 may retire prior to age 65 and receive an unreduced benefit. Ms. Gagle and Mr. Aydt each have vested legacy retirement benefits under the plan. These benefits remain subject to reduction as neither Ms. Gagle nor Mr. Aydt has reached age 62. Available benefits include various annuity options and a lump sum distribution option. Participants are eligible for early retirement upon reaching age 50 and completing 10 years of vesting service. If an employee retires between the ages of 50 and 62 with sufficient vesting service, the amount of benefit under the legacy benefit formula is reduced as follows:
| Age at Retirement | 62 | 61 | 60 | 59 | 58 | 57 | 56 | 55 | 54 | 53 | 52 | 51 | 50 | ||||||||||||||||||||||||||||
| Early Retirement Factor | 100 | % | 97 | % | 94 | % | 91 | % | 87 | % | 83 | % | 79 | % | 75 | % | 71 | % | 67 | % | 63 | % | 59 | % | 55 | % | |||||||||||||||
Cash Balance Benefit
Starting in 2010, benefit accruals are determined under the following cash balance formula.
| MPC Cash Balance Formula | ||||||||||||||||||||||||||
| Annual Compensation | × | Pay Credit Percentage | ð | Participants receive pay credit percentages based on the sum of their age and cash balance service: | ||||||||||||||||||||||
| + | Account Balance | × | Interest Credit Rate | Participant Points | Fewer than 50 Points | 50-69 Points | 70 Points or More | |||||||||||||||||||
| Cash Balance Annual Benefit | Pay Credit Percentage | 7% | 9% | 11% | ||||||||||||||||||||||
Annual compensation is limited to $290,000 for 2021 and generally includes wages and salary for time worked, with certain exclusions. Under the cash balance retirement benefit, a vested participant may retire at any age prior to 65 and receive an unreduced benefit. Each NEO has vested cash balance retirement benefits under the plan that are not subject to reduction upon retirement. Under the cash balance formula, plan participants receive pay credits based on age and cash balance service. For 2021, Mses. Gagle and Beall and Mr. Aydt received pay credits equal to 11% of compensation, and Messrs. Hennigan, Quaid and Floerke received pay credits equal to 9% of compensation. There are no early retirement subsidies under the cash balance formula.
MPC Excess Benefit Plan (Defined Benefit Portion)
The MPC Excess Benefit Plan is an unfunded nonqualified deferred compensation plan maintained for the benefit of a select group of management or highly compensated employees. This plan generally provides benefits that participants, including our NEOs, would have otherwise received under the tax-qualified MPC Retirement Plan were it not for Internal Revenue Code limitations. For our NEOs, eligible earnings under the plan include the compensation items listed above for the MPC Retirement Plan, but without regard to any Internal Revenue Code
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limit, as well as any salary and bonus amounts deferred by the NEO under the MPC Executive Deferred Compensation Plan.
With respect to Mses. Gagle and Beall and Mr. Aydt, who have frozen legacy-type benefits under the plan, eligible earnings for the legacy-type portion were determined using each NEO’s highest consecutive 36-month compensation (exclusive of bonuses) and three highest bonuses earned over the 10-year period up to December 31, 2012. None of our other NEOs have a legacy-type benefit under the plan.)
Due to the structure of the frozen MPC legacy benefit formula under the MPC Retirement Plan, the age-related benefit conversion factors used to calculate lump sum benefits under the frozen legacy benefit formula result in a year-to-year decrease in the lump sum benefit for participants generally beginning on or after the age of 59. As a result, if participants choose to continue their employment with MPC after they reach age 59, their lump sum benefit may decline year to year.
The MPC Excess Benefit Plan permits MPC’s Compensation Committee, on a discretionary basis, to extend a lump sum retirement benefit supplement (“Service Benefit”) to individual officers of MPC who have a frozen legacy-type benefit under the plan to offset the age-related erosion (if any) of the frozen legacy-type benefit from age 62 until such officer’s actual retirement date or date of death. An officer must be vested under the MPC Retirement Plan to qualify for the Service Benefit. Each of Mses. Gagle and Beall and Mr. Aydt have a frozen legacy-type benefit under the plan; however, the Committee has not extended eligibility for this benefit to them at this time.
Tax-Qualified Defined Contribution Retirement Plan
The MPC Thrift Plan is a tax-qualified, defined contribution retirement plan. In general, all of MPC’s employees, including our NEOs, are immediately eligible to participate in the plan. The purpose of the plan is to assist employees in maintaining a steady program of savings to supplement their retirement income and to meet other financial needs.
The MPC Thrift Plan allows eligible employees, such as our NEOs, to make elective deferral contributions to their plan accounts on a pre-tax or after-tax “Roth” basis from 1% to a maximum of 75% of their plan-considered gross pay, with such gross pay limited to the applicable Internal Revenue Code annual compensation limit ($290,000 for 2021). Eligible employees who are “highly compensated employees” as determined under the Internal Revenue Code, such as our NEOs, may additionally make after-tax contributions to their plan accounts from 1% to 2% of their plan-considered gross pay limited to the applicable Internal Revenue Code annual compensation limit ($290,000 for 2021). Employer matching contributions are made on such elective deferrals and after-tax contributions at a rate of 117% up to a maximum of 6% of an employee’s plan-considered gross pay. All employee elective deferrals and after-tax contributions, and all employer matching contributions made, are fully vested.
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2021 NONQUALIFIED DEFERRED COMPENSATION
The following table provides information regarding MPC’s nonqualified savings and deferred compensation plans.
| Name | Plan | Executive Contributions in Last Fiscal Year ($) | MPC Company Contributions in Last Fiscal Year ($) | Aggregate Earnings in Last Fiscal Year ($) | Aggregate Withdrawals/Distributions ($) | Aggregate Balance at Last Fiscal Year-End ($) | ||||||||||||||
| Hennigan | MPC Deferred Compensation Plan | 615,867 | 43,234 | 900,617 | — | 5,341,748 | ||||||||||||||
| MPC Executive Deferred Compensation Plan | — | 264,897 | 14,563 | — | 279,461 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 5,713 | 23,486 | 15,920 | |||||||||||||||
| MPLX LP 2012 Incentive Compensation Plan | — | — | 5,517 | 63,953 | — | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 14,379 | 19,408 | 28,886 | |||||||||||||||
| Quaid | MPC Deferred Compensation Plan | — | — | 61,181 | — | 494,891 | ||||||||||||||
| MPC Executive Deferred Compensation Plan | — | 55,082 | 3,509 | — | 58,591 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 1,295 | 6,188 | 3,442 | |||||||||||||||
| MPLX LP 2012 Incentive Compensation Plan | — | — | 441 | 5,118 | — | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 3,110 | 14,433 | 6,248 | |||||||||||||||
| Gagle | MPC Excess Benefit Plan | — | — | 1,235 | — | 109,643 | ||||||||||||||
| MPC Deferred Compensation Plan | — | — | 70,530 | — | 464,269 | |||||||||||||||
| MPC Executive Deferred Compensation Plan | 140,000 | 83,304 | 23,156 | — | 246,460 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 18,162 | 11,731 | 22,523 | |||||||||||||||
| MPLX LP 2012 Incentive Compensation Plan | — | — | 2,520 | 29,221 | — | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 56,465 | 11,448 | 61,507 | |||||||||||||||
| Floerke | MPC Deferred Compensation Plan | — | — | 94,914 | — | 531,527 | ||||||||||||||
| MPC Executive Deferred Compensation Plan | — | 59,296 | 2,637 | — | 61,932 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 9,096 | 6,817 | 11,543 | |||||||||||||||
| MPLX LP 2012 Incentive Compensation Plan | — | — | 123,497 | 18,273 | 564,375 | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 28,075 | 6,219 | 31,024 | |||||||||||||||
| Aydt | MPC Excess Benefit Plan | — | — | 2,002 | — | 177,716 | ||||||||||||||
| MPC Deferred Compensation Plan | — | — | 24,582 | — | 130,888 | |||||||||||||||
| MPC Executive Deferred Compensation Plan | — | 46,602 | 1,979 | — | 48,581 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 8,967 | 7,726 | 9,875 | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 27,189 | 11,734 | 28,087 | |||||||||||||||
| Beall | MPC Excess Benefit Plan | — | — | 1,656 | — | 146,957 | ||||||||||||||
| MPC Deferred Compensation Plan | — | — | 127,294 | — | 1,552,441 | |||||||||||||||
| MPC Executive Deferred Compensation Plan | — | 58,326 | 379 | — | 58,706 | |||||||||||||||
| MPC 2012 Incentive Compensation Plan | — | — | 15,965 | 7,225 | 21,247 | |||||||||||||||
| MPLX LP 2012 Incentive Compensation Plan | — | — | 1,576 | 18,275 | — | |||||||||||||||
| MPLX LP 2018 Incentive Compensation Plan | — | — | 43,619 | 7,073 | 51,425 | |||||||||||||||
Executive Contributions are also included in the “Salary” and “Non-Equity Incentive Plan Compensation” columns of the “2021 Summary Compensation Table.”
Company Contributions are also included in the “All Other Compensation” column of the “2021 Summary Compensation Table.”
Aggregate Earnings for long-term incentive and incentive compensation plans include accrued dividends/dividend equivalents and distribution equivalents on nonforfeitable awards.
Aggregate Withdrawals/Distributions represent the payment of dividends/dividend equivalents and distribution equivalents accrued on nonforfeitable awards.
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Aggregate Balance at Last Fiscal Year-End. Of the amounts shown, the following amounts have been reported in our “Summary Compensation Table” for previous years:
| Hennigan | Gagle | Floerke | Aydt | Beall | |||||||||||||
MPC Deferred Compensation Plan | 2,707,097 | 191,902 | 281,099 | 48,686 | 334,068 | ||||||||||||
MPC Excess Benefit Plan (Defined Contribution Portion)
Certain highly compensated non-officer employees are eligible for the MPC Excess Benefit Plan’s defined contribution portion. Participants receive employer matching contributions equal to the amount they would have otherwise received under the tax-qualified MPC Thrift Plan were it not for Internal Revenue Code limitations.
Defined contribution accruals in the MPC Excess Benefit Plan are credited with interest equal to that paid in a specified investment option of the MPC Thrift Plan, which was 1.14% for the year ended December 31, 2021. All plan distributions are paid in a lump sum following the participant’s separation from service. In general, our NEOs no longer actively participate in the defined contribution portion of the MPC Excess Benefit Plan, and all subsequent year nonqualified employer matching contributions for NEOs now accrue under the MPC Executive Deferred Compensation Plan.
MPC Deferred Compensation Plan
The MPC Deferred Compensation Plan is an unfunded nonqualified deferred compensation plan maintained for the benefit of a select group of management or highly compensated employees, including our NEOs. Effective January 1, 2021, the plan was generally frozen with respect to any further MPC participant salary and bonus deferrals and additional company contribution credited amounts, provided, however that: (i) deferrals in 2021 of participants’, including our NEOs’, bonus amounts payable in 2021 that were attributable to a 2020 performance period, were permitted; and (ii) MPC senior executives, including our NEOs, who are not otherwise eligible to commence participation in the MPC Executive Deferred Compensation Plan, and who are approved for participation in the plan by MPC’s Chief Human Resources Officer, are credited with an amount equal to the matching contributions the participant would have received, but for Internal Revenue Code limitations and compensation limits, under the MPC Thrift Plan. Prior to the plan’s freeze, participants could defer up to 20% of their salary and bonus each year in a tax-advantaged manner, with irrevocable deferral elections made in December of each year for amounts to be earned in the following year. This 20% deferral limit applied to the bonus amounts payable in 2021 feature described in clause (i) above. The plan credited matching contributions on a participant’s deferrals equal to the match under the MPC Thrift Plan (117% as in effect prior to the plan’s freeze) plus an amount equal to the matching contributions the participant would have received, but for Internal Revenue Code limitations and compensation limits, under the MPC Thrift Plan. Participants are fully vested in all amounts credited on their behalf under the plan. Participants may make notional investments of their notional plan accounts from among certain investment options offered under the MPC Thrift Plan, and participants’ notional plan accounts are credited with notional earnings and losses based on the result of those investment elections. Participants generally receive payment of their plan benefits in a lump sum following separation from service.
MPC Executive Deferred Compensation Plan
The MPC Executive Deferred Compensation Plan, effective January 1, 2021, is an unfunded nonqualified deferred compensation plan maintained for the benefit of a select group of management or highly compensated employees, including our NEOs. Participants may defer 5% to 20% (in whole percentage increments) of their base salary and annual bonus each year in a tax-advantaged manner. Deferral elections are made each December for amounts to be earned in the following year and are irrevocable. The plan credits matching contributions on a participant’s deferrals equal to the match under the MPC Thrift Plan plus an amount equal to the matching contributions the participant would have received, but for Internal Revenue Code limitations and compensation limits, under the MPC Thrift Plan. Participants are fully vested in their deferrals and matching contributions. Participants may make notional investments of their notional plan accounts from among certain investment options offered under the MPC Thrift Plan, and participants’ notional plan accounts are credited with notional earnings and losses based on the result of those investment elections. Participants may elect to receive payment of their plan benefits in a lump sum or in annual installments over two to five years on or beginning on a specified date while in service or following separation from service.
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Section 409A Compliance
All of MPC’s nonqualified deferred compensation plans in which our NEOs participate are intended to comply with, or be exempt from, Section 409A of the Internal Revenue Code. As a result, distribution of amounts subject to Section 409A may be delayed for six months following retirement or other separation from service where the participant is considered a “specified employee” for purposes of Section 409A. All of our NEOs are “specified employees” for purposes of Section 409A.
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POTENTIAL PAYMENTS UPON A TERMINATION OR CHANGE IN CONTROL
The following table provides information regarding the amount of compensation payable to our current NEOs as a direct result of each specified hypothetical termination scenario, assuming that the applicable termination event occurred on December 31, 2021, based on the plans and agreements in place on that date. The actual payments to which an NEO would be entitled may only be determined based upon the actual occurrence and circumstances surrounding the termination.
| Name | Scenario | Severance ($) | Additional Legacy Pension Benefits ($) | Stock Options Vested ($) | RSUs/Restricted Stock/Phantom Units Vested ($) | Performance Units/PSUs Vested ($) | Other Benefits ($) | Total ($) | ||||||||||||||||||
| Hennigan | Voluntary Termination | — | — | — | — | — | — | — | ||||||||||||||||||
| Involuntary Termination without Cause or with Good Reason | — | — | — | — | — | — | — | |||||||||||||||||||
| Involuntary Termination for Cause | — | — | — | — | — | — | — | |||||||||||||||||||
| Change in Control with Qualified Termination | 10,548,301 | — | 1,224,915 | 19,103,772 | 10,507,714 | 17,213 | 41,401,915 | |||||||||||||||||||
| Death | — | — | 1,224,915 | 19,103,772 | 10,507,714 | — | 30,836,401 | |||||||||||||||||||
| Quaid | Voluntary Termination | — | — | — | — | — | — | — | ||||||||||||||||||
| Involuntary Termination without Cause or with Good Reason | — | — | — | — | — | — | — | |||||||||||||||||||
| Involuntary Termination for Cause | — | — | — | — | — | — | — | |||||||||||||||||||
| Change in Control with Qualified Termination | 3,675,000 | — | 213,039 | 590,951 | 952,140 | 9,966 | 5,441,096 | |||||||||||||||||||
| Death | — | — | 213,039 | 590,951 | 952,140 | — | 1,756,130 | |||||||||||||||||||
| Gagle | Voluntary Termination | — | — | — | — | — | — | — | ||||||||||||||||||
| Involuntary Termination without Cause or with Good Reason | — | — | — | — | — | — | — | |||||||||||||||||||
| Involuntary Termination for Cause | — | — | — | — | — | — | — | |||||||||||||||||||
| Change in Control with Qualified Termination | 4,350,000 | 9,463,530 | — | 482,631 | 333,334 | 11,055 | 14,640,550 | |||||||||||||||||||
| Death | — | — | — | 482,631 | 333,334 | — | 815,965 | |||||||||||||||||||
| Floerke | Voluntary Termination | — | — | — | — | — | — | — | ||||||||||||||||||
| Involuntary Termination without Cause or with Good Reason | — | — | — | — | — | — | — | |||||||||||||||||||
| Involuntary Termination for Cause | — | — | — | — | — | — | — | |||||||||||||||||||
| Change in Control with Qualified Termination | 3,540,000 | — | 266,290 | 1,320,705 | 433,333 | 7,840 | 5,568,168 | |||||||||||||||||||
| Death | — | — | 266,290 | 1,320,705 | 433,333 | — | 2,020,328 | |||||||||||||||||||
| Aydt | Voluntary Termination | — | — | — | — | — | — | — | ||||||||||||||||||
| Involuntary Termination without Cause or with Good Reason | — | — | — | — | — | — | — | |||||||||||||||||||
| Involuntary Termination for Cause | — | — | — | — | — | — | — | |||||||||||||||||||
| Change in Control with Qualified Termination | 2,625,000 | 6,328,087 | — | 144,877 | 100,000 | 7,317 | 9,205,281 | |||||||||||||||||||
| Death | — | — | — | 144,877 | 100,000 | — | 244,877 | |||||||||||||||||||
Severance. Under the MPLX LP Executive Change in Control Severance Benefits Plan, as further described below, cash severance will only be paid upon a change in control if the NEO experiences a Qualified Termination (as defined below). If the Qualified Termination occurs within three years prior to the date the NEO reaches age 65, the NEO’s benefit will be limited to a pro rata portion of the benefit. Mr. Hennigan’s benefit has been reduced as he is within three years of reaching age 65.
Pension Benefits for our NEOs are reflected in the “2021 Pension Benefits Table” above. Amounts in this potential payments table represent additional pension benefits attributable solely to the legacy benefit formula in the MPC Retirement Plan, further described beginning on page 170. The incremental retirement benefits included in these amounts were calculated using the following assumptions: individual life expectancies using the RP2000 Combined Healthy Table weighted 75% male and 25% female; a discount rate of 0.00% for NEOs who are retirement eligible (taking into account the additional three years of age and service credit) and 0.00% for NEOs who are not retirement eligible; the current lump-sum interest rate for the relevant plans; and a lump-sum form of benefit. Only Ms. Gagle and Mr. Aydt are eligible for this enhanced benefit under the legacy benefit formula as it is applicable only to individuals who participated in the MPC Retirement Plan prior to 2010.
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Vested Equity (Stock Options, RSUs/Restricted Stock, Phantom Units and Performance Units)
The amounts in this table reflect the value of equity that would vest on an accelerated basis as a direct result of each applicable scenario. Each of our NEOs holds certain awards that have become nonforfeitable by their terms. Awards no longer subject to forfeiture irrespective of the termination scenario are not included in this table. See the tables and accompanying narrative under “Outstanding Equity Awards at 2021 Fiscal Year-End” for more information about these nonforfeitable awards and their respective vesting dates.
Vesting of stock options is accelerated upon retirement or a change in control with a Qualified Termination. Amounts shown reflect the value realized if accelerated stock options were exercised on December 31, 2021, taking into account the spread (if any) between the options’ exercise prices and the closing price of our common stock ($63.99) on December 31, 2021.
Vesting of MPC RSUs/restricted stock and MPLX phantom units is accelerated upon a change in control with a Qualified Termination. Amounts shown reflect the value realized if MPC RSUs/restricted stock and MPLX phantom unit awards vested on December 31, 2021, taking into account the closing price of our common stock ($63.99) and MPLX common units ($29.59) on December 31, 2021. In the event of Mr. Floerke’s termination of employment for any reason other than for cause, the MPLX phantom units he received as part of his retention award in 2015 will become payable.
In the event of a change in control and a Qualified Termination, unvested MPC and MPLX performance units/PSUs will vest and be paid out based on actual performance for the period from the grant date to the change in control date, and target performance for the period from the change in control date to the end of the performance cycle. Amounts shown reflect the MPC and MPLX performance unit/PSU amounts payable in each scenario, calculated using the target value ($1.00) for each MPC and MPLX performance unit and the target value ($63.99) for each PSU (the closing price of our common stock on December 31, 2021).
Other Benefits include 36 months of continued health, dental and life insurance coverage. In the event of death, life insurance would be paid out to the estates of our NEOs in the following amounts: Mr. Hennigan, $3.2 million; Mr. Quaid, $1.1 million; Ms. Gagle, $1.4 million; Mr. Floerke, $1.1 million; Mr. Aydt, $0.8 million.
Voluntary Termination
Resignation
Upon an NEO’s voluntary resignation, LTI awards still subject to forfeiture, including vested but unexercised stock options, generally are forfeited unless provided otherwise in the applicable award agreement. As discussed above under “Outstanding Equity Awards at 2021 Fiscal Year-End,” certain awards held by each of our NEOs have become nonforfeitable by their terms and thus would not be forfeited in the event of resignation.
Retirement
Our employees generally are eligible for retirement once they reach age 50 and have at least 10 years of vesting service with MPC or its subsidiaries. As of December 31, 2021, Ms. Gagle and Mr. Aydt were retirement eligible. Retirement-eligible NEOs are eligible for a prorated bonus under the ACB program in their year of retirement based on their eligible earnings for the year. Upon retirement, our NEOs are entitled to receive their vested benefits that have accrued under our employee and executive benefit programs. For more information about our retirement and deferred compensation programs, see “2021 Pension Benefits” and “2021 Nonqualified Deferred Compensation.”
In addition, upon retirement, our NEOs’ unvested stock options become exercisable according to the grant terms and expire upon the earlier of five years following the closing and the existing expiration date applicable to each such option. MPC RSUs/restricted stock and MPLX phantom units still subject to forfeiture generally are forfeited upon retirement (except in the case of mandatory retirement at age 65, when they vest in full). If an NEO has worked more than nine months of the performance cycle, performance awards may vest on a prorated basis at the discretion of MPC’s Compensation Committee (the MPLX Committee, in the case of MPLX performance units). In the case of mandatory retirement, performance units will fully vest; however, payout will occur following the full performance cycle based on its certified results.
Pursuant to MPC’s mandatory retirement age policy, Ms. Beall ceased service as our CFO effective September 1, 2021, and retired effective November 30, 2021. As reflected above in the 2021 Summary Compensation Table, she received upon her retirement a $100,071 lump sum payment representing her vested but unused vacation benefit, and was eligible for a prorated bonus under MPC’s 2021 ACB program based on her eligible earnings for 2021. As a
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result of her mandatory retirement, Ms. Beall’s outstanding unvested stock options vested and became immediately exercisable, her outstanding MPC restricted stock/RSUs and MPLX phantom units vested, and her outstanding MPC and MPLX performance units became nonforfeitable and will be paid out following certification of each applicable performance cycle. Amounts Ms. Beall received under MPC’s qualified retirement and nonqualified deferred compensation plans as a result of her retirement are described above under ”Post-Employment Benefits for 2021” and “2021 Nonqualified Deferred Compensation.”
Approved Separation
Under the terms of MPC’s and our 2021 LTI award agreements, our NEOs generally are eligible for an Approved Separation once they reach age 55 and have at least five years of employment with MPC or its subsidiaries. As of December 31, 2021, Ms. Gagle and Messrs. Floerke and Aydt were eligible for an Approved Separation. Under an Approved Separation scenario, 2021 MPC RSUs, MPC PSUs and MPLX phantom units would become nonforfeitable upon an eligible NEO’s resignation provided he or she had held such awards at least six months and provided notice at least 180 days prior to such resignation. MPC’s Compensation Committee may, in its sole discretion, waive this notice requirement.
Involuntary Termination Without Cause or With Good Reason
Neither MPC nor we generally enter into employment or severance agreements with our NEOs. An NEO whose employment is terminated by us without cause, or who terminates his employment with good reason, is eligible for the same termination allowance plan available to all other MPC employees, which would pay (i) an amount between eight and 62 weeks of salary based either on service or salary level, and (ii) in the case of our current NEOs, an additional amount equal to the NEO’s target bonus under MPC’s ACB program prorated for service up to the termination date. Upon involuntary termination of an NEO without cause, or termination with good reason, vested stock options generally are exercisable for 90 days following termination.
Involuntary Termination for Cause
Upon an NEO’s involuntary termination for cause, unvested LTI awards, including vested but unexercised stock options, generally are forfeited unless provided otherwise in the applicable award agreement.
Death
In the event of death, our NEOs (or their beneficiaries) are entitled to the vested benefits they have accrued under MPC’s employee benefit programs. In the event of the death of an NEO during the ACB performance period, unless otherwise determined by MPC’s Compensation Committee, a target bonus will be paid. LTI awards immediately vest in full upon death, with performance units vesting at the target level.
Change in Control
Our NEOs participate in two change in control severance plans: the MPC Amended and Restated Executive Change in Control Severance Benefits Plan (“MPC CIC Plan”) and the MPLX Executive Change in Control Severance Benefits Plan (“MPLX CIC Plan”). These change in control plans were designed to (i) preserve executives’ economic motivation to consider a business combination that might result in job loss and (ii) compete effectively in attracting and retaining executives in an industry that features frequent mergers, acquisitions and divestitures.
Benefits under each plan are payable only upon a change in control and a Qualified Termination. The following table shows the benefits for which our NEOs would be eligible upon a change in control of MPC or MPLX and a Qualified Termination with the applicable entity. In the event of a change in control and Qualified Termination under both plans, our NEOs would receive benefits under only one plan – whichever provides the greater benefits at that time.
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| CHANGE IN CONTROL OF MPC | CHANGE IN CONTROL OF MPLX | ||||||||||
| A lump sum cash payment of up to three times the sum of the NEO’s current annualized base salary plus three times the highest bonus paid in the three years before the termination or change in control. | |||||||||||
| Life and health insurance benefits for up to 36 months after termination at the lesser of the current cost or the active employee cost. | Life and health insurance benefits for up to 36 months after termination at the active employee cost. | ||||||||||
| An additional three years of service credit and three years of age credit for purposes of retiree health and life insurance benefits. | |||||||||||
| A lump sum cash payment equal to the actuarial equivalent of the difference between amounts receivable by the NEO under the final average pay formula in our pension plans and those payable if: (i) the NEO had an additional three years of participation service credit; (ii) the NEO’s final average pay were the higher of the NEO’s salary at the time of the change in control event or Qualified Termination plus the NEO’s highest annual bonus from the preceding three years (for purposes of determining early retirement commencement factors, the NEO is credited with three additional years of vesting service and three additional years of age); and (iii) the NEO’s pension had been fully vested. | |||||||||||
| A lump sum cash payment equal to the difference between amounts receivable under our tax-qualified and nonqualified defined contribution type retirement and deferred compensation plans and amounts that would have been received if the NEO’s defined contribution plan account had been fully vested. | |||||||||||
| Accelerated vesting of all outstanding MPC LTI awards. | Accelerated vesting of all outstanding MPLX LTI awards. | ||||||||||
The MPLX CIC Plan also provides that NEOs who don’t technically incur a Qualified Termination but separate from service with MPLX as a result of an MPLX change in control (in other words, where the NEO remains employed with MPC but no longer provides services to MPLX) will become fully vested in all outstanding MPLX LTI awards. NEOs who receive an offer for comparable employment from an acquirer or successor entity in an MPLX change in control will not be eligible to receive benefits under the MPLX CIC Plan.
A “Qualified Termination” generally occurs when an NEO’s employment with our affiliates and us ends in connection with, or within two years after, a change in control. Exceptions include: | ||||||||||||||
● | Separation due to death or disability | ● | Voluntary termination without good reason (“good reason” includes a material reduction in roles, responsibilities, pay or benefits, or being required to relocate more than 50 miles from one’s current location) | |||||||||||
● | Termination for cause | |||||||||||||
● | Termination after age 65 | |||||||||||||
CEO PAY RATIO
We do not determine the total compensation of our CEO or of any of the other personnel responsible for managing and operating our business, all of whom are employed by MPC and not by our general partner or us. Because we do not directly employ any employees and do not determine or pay total compensation to the employees of MPC who manage and operate our business, we do not have a median employee whose total compensation can be compared to the total compensation of our CEO.
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DIRECTOR COMPENSATION
Officers or employees of our general partner or MPC who also serve as our directors do not receive additional compensation for their service as our director. Directors who are not officers or employees of our general partner or MPC receive compensation as “non-employee directors.”
Compensation Program for Non-Employee Directors
Following is the compensation package established for our non-employee directors for 2021:
| Role | Cash Retainer ($) | Deferred Phantom Unit Equity Award ($) | Lead Director Retainer ($) | Committee Chair Retainer ($) | MLP Representative Retainer ($) | Total ($) | |||||||||||||||||||||||
| Lead Director | 90,000 | 110,000 | 15,000 | — | — | 215,000 | |||||||||||||||||||||||
| Audit Committee Chair | 90,000 | 110,000 | — | 15,000 | — | 215,000 | |||||||||||||||||||||||
| Conflicts Committee Chair | 90,000 | 110,000 | — | 15,000 | — | 215,000 | |||||||||||||||||||||||
| MLP Representative Board Observer | 90,000 | 110,000 | — | — | 62,500 | 262,500 | |||||||||||||||||||||||
| All Other Directors | 90,000 | 110,000 | — | — | — | 200,000 | |||||||||||||||||||||||
The cash retainer, lead director retainer and committee chair retainers are paid in equal installments on a quarterly basis. Members of the Conflicts Committee also receive a meeting fee of $1,500 for each Conflicts Committee meeting attended in excess of six meetings per year.
The equity retainer, in the form of phantom units, is granted in equal installments on a quarterly basis.
Directors receive MPLX distribution equivalents in the form of additional MPLX phantom units. The phantom units, including those received as distribution equivalents, are deferred, payable in common units only upon a director’s departure from the Board.
Under MPC’s matching gifts program, non-employee directors may elect to have MPC match up to $10,000 of their contributions to certain tax-exempt educational institutions each year.
2022 Program Changes
In October 2021, following a review of market data, the Board determined to increase the annual cash retainers for the Lead Director, the Audit Committee Chair and the Conflicts Committee Chair to $20,000, $20,000 and $20,000, respectively, effective January 1, 2022.
2021 Director Compensation Table
The following table shows compensation earned by or paid to our non-employee directors during 2021.
| Name | Fees Earned or Paid in Cash ($) | Unit Awards ($) | All Other Compensation ($) | Total ($) | |||||||||||||||||||||||||
Michael L. Beatty(1) | 27,445 | 33,544 | 15,000 | 75,989 | |||||||||||||||||||||||||
| Christopher A. Helms | 105,000 | 110,000 | — | 215,000 | |||||||||||||||||||||||||
| Garry L. Peiffer | 105,000 | 110,000 | 4,000 | 219,000 | |||||||||||||||||||||||||
| Dan D. Sandman | 105,000 | 110,000 | 20,000 | 235,000 | |||||||||||||||||||||||||
| Frank M. Semple | 110,433 | 110,000 | — | 220,433 | |||||||||||||||||||||||||
| J. Michael Stice | 90,000 | 110,000 | — | 200,000 | |||||||||||||||||||||||||
| John P. Surma | 90,000 | 110,000 | — | 200,000 | |||||||||||||||||||||||||
Donald C. Templin(2) | 37,419 | 45,734 | 10,000 | 93,153 | |||||||||||||||||||||||||
(1) Retired from Board service effective April 20, 2021 pursuant to our mandatory retirement policy for directors. | |||||||||||||||||||||||||||||
(2) Began receiving compensation as a non-employee director effective August 1, 2021, following retirement from employment with MPC. | |||||||||||||||||||||||||||||
Compensation for Ms. Beall, who served as a non-employee director from December 1, 2021, following her retirement from employment with MPC, through December 31, 2021, is shown above in the “All Other Compensation” column of the 2021 Summary Compensation Table.
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Fees Earned or Paid in Cash reflect cash retainers earned for Board service in 2021. For Mr. Semple, this amount also includes $20,433 in compensation for service as our Representative Observer, in which role he attended certain MPC Board and committee meetings as a liaison between the MPC Board and us. We ceased compensating Mr. Semple for this role upon his election to the MPC Board effective April 28, 2021.
Unit Awards reflect the aggregate grant date fair value of phantom units, calculated in accordance with FASB ASC Topic 718. Non-employee directors generally received grants each quarter of phantom units valued at $27,500 based on the closing price of our common units on each grant date. The aggregate number of phantom units in respect of Board service outstanding for each non-employee director as of December 31, 2021 is: Mr. Helms, 37,557; Mr. Peiffer, 33,572; Mr. Sandman, 37,557; Mr. Semple, 25,987; Mr. Stice, 20,249; Mr. Surma, 37,557.
All Other Compensation reflects contributions made to educational institutions under MPC’s matching gifts program, as described above. This program is subject to an annual limit of $10,000; however, the actual amount paid out on behalf of a director may exceed $10,000 in a given year due to end-of-year processing delays. The amount for Mr. Beatty also includes a $5,000 gift made by MPC to a charitable organization in Mr. Beatty’s honor upon his retirement from the Board.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Management
The following table sets forth the number of our common units and shares of MPC common stock beneficially owned as of February 1, 2022 by each director and NEO, and by all current directors and executive officers as a group. The address for each person named below is c/o MPLX LP, 200 East Hardin Street, Findlay, Ohio 45840. Unless otherwise indicated, to our knowledge, each person or member of the group listed has sole voting and investment power with respect to the securities shown, and none of the shares or units shown is pledged as security. As of February 1, 2022, there were 1,014,982,223 MPLX common units outstanding (including 647,415,452 common units held by MPC and its affiliates) and 570,865,701 shares of MPC common stock outstanding.
| Name of Beneficial Owner | Amount and Nature of Beneficial Ownership | Percent of Total Outstanding (%) | ||||||||||||||||||
| MPLX Common Units | MPC Common Stock | MPLX | MPC | |||||||||||||||||
| Current Non-Executive Directors | ||||||||||||||||||||
| Christopher A. Helms | 49,476 | — | * | * | ||||||||||||||||
| Maryann T. Mannen | 33,127 | 86,323 | * | * | ||||||||||||||||
| Garry L. Peiffer | 102,987 | 63,394 | * | * | ||||||||||||||||
| Dan D. Sandman | 119,106 | — | * | * | ||||||||||||||||
| Frank M. Semple | 550,061 | 7,794 | * | * | ||||||||||||||||
| J. Michael Stice | 26,044 | 16,883 | * | * | ||||||||||||||||
| John P. Surma | 52,774 | 59,761 | * | * | ||||||||||||||||
| Named Executive Officers | ||||||||||||||||||||
| Michael J. Hennigan | 212,730 | 510,667 | * | * | ||||||||||||||||
| John J. Quaid | 18,838 | 106,675 | * | * | ||||||||||||||||
| Suzanne Gagle | 49,067 | 181,307 | * | * | ||||||||||||||||
| Gregory S. Floerke | 79,336 | 69,784 | * | * | ||||||||||||||||
| Timothy J. Aydt | 27,365 | 73,108 | * | * | ||||||||||||||||
| Pamela K.M. Beall | 53,247 | 128,128 | * | * | ||||||||||||||||
| All Current Directors and Executive Officers as a group (14 individuals) | 1,336,139 | 1,276,705 | * | * | ||||||||||||||||
* Less than 1% of common units or common shares outstanding, as applicable.
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MPLX Common Unit beneficial ownership amounts include:
•Phantom unit awards, which settle in common units upon a director’s retirement from service on the Board, as follows: Mr. Helms, 38,476; Mr. Peiffer, 34,490; Mr. Sandman, 38,476; Mr. Semple, 28,767; Mr. Stice, 25,344; Mr. Surma, 45,274.
•Phantom unit awards, which may be forfeited under certain conditions, as follows: Mr. Hennigan, 112,016; Mr. Quaid, 10,056; Ms. Gagle, 26,254; Mr. Floerke, 49,506; Mr. Aydt, 11,387; Ms. Mannen, 33,127; all other executives, 7,998.
•Common units indirectly beneficially held in trust as follows: Mr. Peiffer, 68,497; Mr. Semple, 472,517; Mr. Stice, 700; Ms. Beall, 10,000.
•For Mr. Semple, includes common units held by or with spouse or by trust for the benefit of spouse.
•For Ms. Beall, who retired from MPC and all affiliated entities, including us, effective November 30, 2021, amounts reported above reflect beneficial ownership of MPLX common units based on information last known or reasonably available to us.
MPC Common Stock beneficial ownership amounts include:
•All stock options exercisable within 60 days of February 1, 2022 as follows: Mr. Hennigan, 167,482; Mr. Quaid, 82,141; Ms. Gagle, 143,047; Mr. Floerke, 46,244; Mr. Aydt, 57,582; Ms. Beall, 83,727; all other executive officers, 75,883.
•Shares of common stock indirectly beneficially held in trust as follows: Ms. Beall, 32,208; Mr. Peiffer, 63,394; Mr. Surma, 10,000.
•For Mr. Surma, includes shares of common stock held by or with spouse or by trust for the benefit of spouse.
•Restricted stock unit awards, which vest upon the director’s retirement from service on the MPC Board, as follows: Mr. Semple, 7,794; Mr. Stice, 16,883; Mr. Surma, 49,761.
•Restricted stock unit awards, which may be forfeited under certain conditions, as follows: Mr. Hennigan, 248,395; Mr. Quaid, 4,942; Ms. Gagle, 12,980; Mr. Floerke, 6,398; Mr. Aydt, 5,538; Ms. Beall, 6,876; Ms. Mannen, 68,370; all other executives, 6,875.
•For Ms. Beall, who retired from MPC and all affiliated entities, including us, effective November 30, 2021, amounts reported above reflect beneficial ownership of shares of common stock based on information last known or reasonably available to us.
Security Ownership of Certain Beneficial Owners
The following table sets forth information as to each unitholder of whom we are aware that, based on filings with the SEC, beneficially owns 5% or more of our outstanding common units as of December 31, 2021:
| Name and Address of Beneficial Owner | Number of Common Units Representing Limited Partner Interests | Percent of Common Units Representing Limited Partner Interests | ||||||||||||
| Marathon Petroleum Corporation | 647,415,452 | 63.8 | % | |||||||||||
| 539 S. Main Street | ||||||||||||||
| Findlay, Ohio 45840 | ||||||||||||||
| The Blackstone Group Inc. | 66,127,749 | 6.5 | % | |||||||||||
| 345 Park Avenue | ||||||||||||||
| New York, New York 10154 | ||||||||||||||
Percent of Common Units is based on 1,014,982,223 MPLX common units outstanding as of February 1, 2022.
Marathon Petroleum Corporation. The MPLX common units are directly held by MPC Investment LLC, MPLX GP LLC, MPLX Logistics Holdings LLC and Giant Industries, Inc. Marathon Petroleum Corporation is the ultimate parent company of MPC Investment LLC, MPLX GP LLC, MPLX Logistics Holdings LLC and Giant Industries, Inc. and may be deemed to beneficially own the MPLX LP common units directly held by these entities.
The Blackstone Group Inc. Amounts derived from a Schedule 13G/A filed with the SEC on February 11, 2022. Per the Schedule 13G/A, the MPLX common units reported above reflect MPLX common units held by funds or
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accounts that may be deemed to be indirectly controlled by The Blackstone Group Inc. The sole holder of the Class C common stock of The Blackstone Group Inc. is Blackstone Group Management L.L.C. Blackstone Group Management L.L.C. is wholly-owned by Blackstone’s senior managing directors and controlled by its founder, Stephen A. Schwarzman.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2021, with respect to common units that may be issued under the MPLX LP 2012 Plan and the MPLX LP 2018 Plan:
| Plan category | Number of securities to be issued upon exercise of outstanding options, warrants and rights | Weighted average exercise price of outstanding options, warrants and rights | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in the first column) | |||||||||||||||||
| Equity compensation plans approved by security holders | 905,040 | N/A | 14,624,345 | |||||||||||||||||
| Equity compensation plans not approved by security holders | — | — | — | |||||||||||||||||
| Total | 905,040 | 14,624,345 | ||||||||||||||||||
Number of Securities to Be Issued includes:
•756,806 phantom unit awards granted pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan for common units unissued and not forfeited, cancelled or expired as of December 31, 2021.
•148,234 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2021, pursuant to the MPLX 2018 Plan based on the closing price of our common units on December 31, 2021, of $29.59 per unit. The number of units reported for this award vehicle may overstate dilution.
Weighted Average Exercise Price. There is no exercise price associated with phantom unit awards or performance unit awards.
Number of Securities Remaining Available reflects the common units available for issuance pursuant to the MPLX 2018 Plan. The number of units reported in this column assumes 148,234 as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2021, pursuant to the MPLX 2018 Plan based on the closing price of our common units on December 31, 2021, of $29.59 per unit. The number of units assumed for this award vehicle may understate the number of common units available for issuance pursuant to the MPLX 2018 Plan.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Policy and Procedures with Respect to Related Person Transactions
The Board has adopted a formal written related person transactions policy establishing procedures for the notification, review, approval, ratification and disclosure of related person transactions. Under the policy, a “related person” includes any director, nominee for director, executive officer, or a known beneficial holder of more than five percent of any class of our voting securities (other than MPC or its affiliates) or any immediate family member of a director, nominee for director, executive officer or more than five percent owner. This procedure applies to any transaction, arrangement or relationship and any series of similar transactions, arrangements or relationships in which (i) we are a participant, (ii) the amount involved exceeds $120,000, and (iii) a related person has a direct or indirect material interest.
The Board has provided its standing pre-approval for the following transactions, arrangements and relationships:
•Payment of compensation to an executive officer or director of our general partner if the compensation is otherwise required to be disclosed in our filings with the SEC;
•Any transaction where the related person’s interest arises solely from the ownership of securities;
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•Any ongoing employment relationship provided that such employment relationship will be subject to initial review and approval; and
•Any transaction between any of our subsidiaries and us, on the one hand, and our general partner or any of its affiliates, on the other hand; provided, however, that such transaction is approved consistent with our Partnership Agreement.
Any related person transaction identified prior to its consummation must be approved in advance by the Board. If the related person transaction is identified after it commences, it will be promptly submitted to the Board or the Chairman for ratification, amendment or rescission. If the transaction has been completed, the Board or the Chairman will evaluate the transaction to determine if rescission is appropriate. Transactions entered into prior to the closing of our initial public offering, when this policy was adopted, were approved by the Board apart from the policy.
In determining whether to approve or ratify a related person transaction, the Board or the Chairman will consider all relevant facts and circumstances, including but not limited to:
•The benefits to us, including the business justification;
•If the related person is a director or an immediate family member of a director, the impact on the director’s independence;
•The availability of other sources for comparable products or services;
•The terms of the transaction and the terms available to unrelated third parties or to employees generally; and
•Whether the transaction is consistent with our Code of Business Conduct.
This policy is available on the “Corporate Governance” page of our website at www.mplx.com/Investors/Corporate_Governance/Policies_and_Guidelines/.
Our Relationship with MPC
As of February 15, 2022, MPC owned through its affiliates 647,415,452 of our common units, representing approximately 64% of our common units outstanding, and 100% of MPLX GP, our general partner. MPLX GP manages our operations and activities through its officers and directors. In addition, various of our officers and directors also serve as officers and/or directors of MPC. Accordingly, we view transactions between MPC and us as related party transactions and have provided the following disclosures with respect to such transactions during 2021. Unless the context otherwise requires, references in the following discussion to “we” or “us” refer to our affiliates and us.
Distributions and Reimbursements to MPC
Pursuant to our Partnership Agreement, we make cash distributions to our unitholders, including MPC. During 2021, we distributed to MPC approximately $2,163 million with respect to the common units it holds.
Under our Partnership Agreement, we reimburse MPLX GP and its affiliates, including MPC, for all costs and expenses incurred on our behalf. The amount we reimbursed in 2021 was $2 million.
Transactions and Commercial and Other Agreements with MPC
We have multiple long-term, fee-based transportation and storage services agreements, as well as a variety of operating services agreements, management services agreements, licensing agreements, employee services agreements, omnibus agreements, a loan agreement, and an aircraft time-sharing agreement with MPC and its consolidated subsidiaries. See “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” in Item 1. Business, and Item 8. Financial Statements and Supplementary Data – Note 6, for information regarding related party activities with MPC.
Director Independence
The information appearing under “Director Independence” in Item 10. Directors, Executive Officers and Corporate Governance is incorporated herein by reference.
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Item 14. Principal Accountant Fees and Services
Auditor Independence
Our Audit Committee has considered whether PricewaterhouseCoopers LLP is independent for purposes of providing external audit services to us and has determined that it is.
Auditor Fees
Following are the aggregate fees for professional services provided to us by PricewaterhouseCoopers LLP for the years ended December 31, 2021, and December 31, 2020:
| (In thousands) | 2021 | 2020 | |||||||||
| Audit | $ | 4,967 | $ | 4,725 | |||||||
| Audit-Related | — | — | |||||||||
| Tax | 1,575 | 1,580 | |||||||||
| All Other | 10 | 10 | |||||||||
| Total | $ | 6,552 | $ | 6,315 | |||||||
Audit fees for the years ended December 31, 2021, and December 31, 2020, were primarily for professional services rendered for the audit of the financial statements and of internal control over financial reporting, the performance of regulatory audits, issuance of comfort letters, the provision of consents and the review of documents filed with the SEC.
Tax fees for the years ended December 31, 2021, and December 31, 2020, were for professional services rendered for the preparation of IRS Schedule K-1 tax forms for MPLX LP unitholders and for income tax consultation services.
All Other fees for the years ended December 31, 2021, and December 31, 2020, were for subscriptions and licenses for online accounting resources provided by PricewaterhouseCoopers LLP.
Pre-Approval of Audit Services
Among other things, our Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services Policy sets forth the procedure for the Audit Committee to pre-approve all audit, audit-related, tax and permissible non-audit services, other than as provided under a de minimis exception. Under the policy, the Audit Committee may pre-approve any services to be performed by our independent auditor up to twelve months in advance and may approve in advance services by specific categories pursuant to a forecasted budget. Annually, the executive vice president and chief financial officer of our general partner will present a forecast of audit, audit-related, tax and permissible non-audit services for the ensuing fiscal year to the Audit Committee for approval in advance. The executive vice president and chief financial officer of our general partner, in coordination with the independent auditor, will provide an updated budget to the Audit Committee, as needed, throughout the ensuing fiscal year.
For unbudgeted items, the Audit Committee has delegated pre-approval authority of up to $250,000 to the Chair of the Audit Committee; such items are reported to the full Audit Committee at its next scheduled meeting.
In 2021 and 2020, the Audit Committee pre-approved all audit, audit-related, tax and permissible non-audit services pursuant to this policy and did not use the de minimis exception.
Part IV
Item 15. Exhibits and Financial Statement Schedules
A. Documents Filed as Part of the Report
1. Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)
2. Financial Statement Schedules
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Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.
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Exhibits:
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 2.1 † | 8-K | 2.1 | 5/8/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 3.1 | S-1 | 3.1 | 7/2/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 3.2 | S-1/A | 3.2 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 3.3 | 8-K | 3.1 | 2/3/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| Pursuant to Item 601(b)(4) of Regulation S-K, certain instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of the Registrant. The Registrant hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request. | ||||||||||||||||||||||||||||||||||||||||||||
| 4.1 | 8-K | 4.1 | 2/12/2015 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 4.2 | 8-K | 4.1 | 5/16/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 4.3 | 10-K | 4.3 | 2/26/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.1* | S-1/A | 10.3 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.2 | 8-K | 10.2 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.3 | S-1/A | 10.6 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.4 | S-1/A | 10.7 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.5 | S-1/A | 10.8 | 9/7/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
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| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.6 | S-1/A | 10.9 | 10/18/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.7 | 8-K | 10.3 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.8 | S-1/A | 10.13 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.9 | S-1/A | 10.14 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.10 | S-1/A | 10.15 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.11 | S-1/A | 10.16 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.12 | S-1/A | 10.17 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 10.13 | 8-K | 10.4 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.14 | 8-K | 10.5 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.15 | 8-K | 10.6 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
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| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.16 | 8-K | 10.7 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.17 | 8-K | 10.8 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.18 | 8-K | 10.9 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.19 | 8-K | 10.10 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.20 | 8-K | 10.11 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.21 | 8-K | 10.12 | 11/6/2012 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.22* | 10-K | 10.26 | 3/25/2013 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.23* | 10-K | 10.30 | 2/24/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.24 | 10-Q | 10.2 | 5/4/2015 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.25 | 10-Q | 10.3 | 5/4/2015 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.26 | 8-K | 10.1 | 6/17/2015 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
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| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.27 | 8-K | 10.1 | 9/23/2015 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.28 | 8-K | 10.1 | 1/4/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.29+ | 10-K | 10.48 | 2/26/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.30 | 8-K | 10.1 | 4/6/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.31 | 8-K | 10.2 | 4/6/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.32 | 8-K | 10.3 | 4/6/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.33 | 8-K | 10.4 | 4/6/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.34* | 10-Q | 10.9 | 5/1/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.35* | 10-Q | 10.7 | 5/2/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.36* | 10-Q | 10.8 | 5/1/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.37* | 10-Q | 10.9 | 5/2/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.38 | 8-K | 10.1 | 4/29/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.39 | 10-Q | 10.2 | 10/31/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
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| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.40 | 10-Q | 10.1 | 8/3/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.41 | 10-Q | 10.2 | 8/3/2016 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.42 | 10-K | 10.62 | 2/24/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.43 | 10-K | 10.63 | 2/24/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.44 | 8-K | 10.1 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.45 | 8-K | 10.2 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.46 | 8-K | 10.3 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.47 | 8-K | 10.4 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.48 | 8-K | 10.5 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.49 | 8-K | 10.6 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
191
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.50 | 8-K | 10.7 | 3/2/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.51* | 10-Q | 10.1 | 8/3/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.52* | 10-Q | 10.2 | 10/30/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.53* | 10-Q | 10.3 | 10/30/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.54 | 8-K | 10.1 | 11/7/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.55 | 8-K | 10.2 | 11/7/2017 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.56+ | 8-K | 10.1 | 2/2/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.57+ | 8-K | 10.2 | 2/2/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.58 | 8-K | 10.3 | 2/2/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.59+ | 8-K | 10.4 | 2/2/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.60 | 8-K | 10.5 | 2/2/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.61* | 8-K | 10.1 | 3/5/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.62* | 10-Q | 10.8 | 4/30/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
192
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.63* | 10-Q | 10.9 | 4/30/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.64* | 10-Q | 10.10 | 4/30/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.65* | 10-Q | 10.11 | 4/30/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.66* | 10-Q | 10.12 | 4/30/2018 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.67* | 10-K | 10.78 | 2/28/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.68* | 10-K | 10.79 | 2/28/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.69* | 10-K | 10.75 | 2/28/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.70* | 10-Q | 10.1 | 5/9/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.71* | 10-Q | 10.2 | 5/9/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.72* | 10-Q | 10.3 | 5/9/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.73* | 10-Q | 10.4 | 5/9/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.74 | 8-K | 10.1 | 8/1/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
193
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.75 | 8-K | 10.2 | 8/1/2019 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.76* | 10-Q | 10.47 | 11/4/2019 | 001-35143 (ANDX) | ||||||||||||||||||||||||||||||||||||||||
| 10.77* | 10-Q | 10.48 | 11/4/2019 | 001-35143 (ANDX) | ||||||||||||||||||||||||||||||||||||||||
| 10.78 | 10-K | 10.102 | 2/28/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.79 | 10-K | 10.103 | 2/28/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.80 | 10-Q | 10.2 | 11/6/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.81* | 10-Q | 10.1 | 5/7/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.82* | 10-Q | 10.2 | 5/7/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.83* | 10-Q | 10.3 | 5/7/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.84* | 10-Q | 10.4 | 5/7/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.85 | 10-Q | 10.1 | 8/3/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.86 | 8-K | 10.1 | 11/5/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.87 | 10-Q | 10.3 | 11/6/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
194
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 10.88 | 10-Q | 10.4 | 11/6/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.89 | 10-Q | 10.5 | 11/6/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.90 | 10-Q | 10.6 | 11/6/2020 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.91 | 10-K | 10.104 | 2/26/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.92* | 10-K | 10.105 | 2/26/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.93 | 10-K | 10.106 | 2/26/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.94 | 10-Q | 10.1 | 11/2/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 21.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 23.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 24.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.2 | X | |||||||||||||||||||||||||||||||||||||||||||
195
| Exhibit Description | Incorporated by Reference | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Form | Exhibit | Filing Date | SEC File No. | ||||||||||||||||||||||||||||||||||||||||
| 32.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 101.INS | Inline XBRL Instance Document | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase | X | ||||||||||||||||||||||||||||||||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101) | |||||||||||||||||||||||||||||||||||||||||||
† The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.
* Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.
+ Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.
196
Item 16. Form 10-K Summary
Not applicable.
197
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| Date: February 24, 2022 | MPLX LP | |||||||
| By: | MPLX GP LLC Its general partner | |||||||
| By: | /s/ Kelly D. Wright | |||||||
| Kelly D. Wright Vice President and Controller of MPLX GP LLC (the general partner of MPLX LP) | ||||||||
198
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 24, 2022 on behalf of the registrant and in the capacities indicated.
| Signature | Title | |||||||
| /s/ Michael J. Hennigan | Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) (principal executive officer) | |||||||
| Michael J. Hennigan | ||||||||
| /s/ John J. Quaid | Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) (principal financial officer) | |||||||
| John J. Quaid | ||||||||
| /s/ Kelly D. Wright | Vice President and Controller of MPLX GP LLC (the general partner of MPLX LP) (principal accounting officer) | |||||||
| Kelly D. Wright | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| Christopher A. Helms | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| Maryann T. Mannen | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| Garry L. Peiffer | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| Dan D. Sandman | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| Frank M. Semple | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| J. Michael Stice | ||||||||
| * | Director of MPLX GP LLC (the general partner of MPLX LP) | |||||||
| John P. Surma | ||||||||
* The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the general partner of the registrant, which is being filed herewith on behalf of such directors and officers.
| By: | /s/ Michael J. Hennigan | February 24, 2022 | ||||||||||||
| Michael J. Hennigan Attorney-in-Fact | ||||||||||||||
199