Item 1. Business
OVERVIEW
We are a diversified, large-cap master limited partnership (“MLP”) formed in 2012 by MPC (as our sponsor) that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. Our assets include a network of crude oil and refined product pipelines; an inland marine business; light-product, asphalt, heavy oil and marine terminals; storage caverns; refinery tanks, docks, loading racks, and associated piping; crude oil and natural gas gathering systems and pipelines; as well as natural gas and NGL processing and fractionation facilities. The operation of these assets are conducted in our Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”) operating segments. Our assets are positioned throughout the United States as depicted in the map below. Our L&S segment primarily engages in the transportation, storage, distribution and marketing of crude oil, asphalt and refined petroleum products. The L&S segment also includes the operation of our inland marine business, terminals, rail facilities, storage caverns and refining logistics. Our G&P segment primarily engages in the gathering, processing and transportation of natural gas as well as the gathering, transportation, fractionation, storage and marketing of NGLs. The assets and operations of our L&S and G&P segments described above include the assets and operations of ANDX acquired via merger on July 30, 2019. This acquisition complemented our existing business in addition to expanding our operations to the West Coast. For more information on these segments, see Our Operating Segments discussion below. The map below and Item 2. Properties provide information about our assets as of December 31, 2019:
We continue to have a strategic relationship with MPC, which is a large source of our revenues. We have executed numerous long-term, fee-based agreements with minimum volume commitments with MPC which provide us with a stable and predictable revenue stream and source of cash flows. This includes agreements obtained through our acquisition of ANDX, whereby ANDX had similar agreements with MPC. As of December 31, 2019, MPC owned approximately 63 percent of our outstanding common units. MPC will continue to be an important source of our revenues and cash flows for the foreseeable future. We also have long-term relationships with a diverse set of producer customers in many crude oil and natural gas
resource plays, including the Permian Basin, Marcellus Shale, Utica Shale, STACK Shale and Bakken Shale, among others.
The growth of our business has provided us with the financial flexibility to maintain an investment grade credit profile and fund our organic growth capital plan with operating cash and debt. We have significant opportunities to develop, expand and participate in projects which complement our existing assets. We continue to evaluate our non-organic growth opportunities through third-party midstream acquisitions to enhance our existing geographic footprint or expand our activities into new areas.
2019 RESULTS
The following table summarizes the operating performance for each segment for the year ended December 31, 2019. For further discussion of our segments and a reconciliation to our Consolidated Statements of Income, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations as well as Item 8. Financial Statements and Supplementary Data - Note 10.
(1)
Includes goodwill impairment of $1.2 billion within our G&P operating segment.
(2)
Includes segment adjusted EBITDA attributable to predecessor.
2019 ACQUISITIONS, INVESTMENTS AND OTHER HIGHLIGHTS
MPLX completed its acquisition of ANDX (the “Merger”) on July 30, 2019. The historical results of ANDX have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired Andeavor (the former sponsor of ANDX). At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The assets of ANDX complement and enhance MPLX’s asset base and further expand MPLX’s existing footprint.
In connection with the Merger, MPLX assumed all outstanding ANDX senior notes, which had an aggregate principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion new unsecured senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX, of which $500 million aggregate principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid off at maturity on October 15, 2019.
During the year, MPLX also: entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement (as defined below) to $3.5 billion; and extended the maturity of the MPLX Credit Agreement to July 30, 2024.
MPLX entered into a joint venture agreement (“Wink to Webster Pipeline JV”) related to the Wink-to-Webster crude oil pipeline, which remains on schedule to be completed in the first half of 2021 and has 100 percent of the contractible capacity committed with minimum volume commitments. This pipeline is designed to be a 36-inch diameter pipeline with a capacity of 1.5 million barrels per day originating in the Permian Basin and with destination points in the Houston market, including MPC’s Galveston Bay refinery.
We also entered into a joint venture agreement related to the design and construction of the Whistler Pipeline. The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport approximately 2 billion Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The majority of available capacity on the planned pipeline has been committed with minimum volume commitments. The pipeline is expected to be in service in the third quarter of 2021.
Additionally, we continue to execute on our organic growth plan through terminal and marine fleet expansions, the expansion of processing and fractionating capacity at numerous plants, as well as having a continued focus on the optimization of our portfolio of assets, which could include asset divestitures.
RECENT DEVELOPMENTS
On February 21, 2020, MPLX, through a wholly-owned subsidiary, formed a joint venture with Delek US Energy, Inc. ("Delek") (the "WWP Project Financing JV") for the specific purpose of financing a portion of MPLX’s and Delek’s combined construction costs for the Wink to Webster pipeline system. Both MPLX and Delek contributed their respective 15 percent ownership interests in the Wink to Webster Pipeline JV to the WWP Project Financing JV. Also on February 21, 2020, the WWP Project Financing JV, through a wholly-owned subsidiary, entered into a committed term loan facility with a syndicate of lenders providing for up to approximately $608 million in term loan borrowings to, among other things, fund future capital calls received from the Wink to Webster Pipeline JV and pay debt service costs under the term loan facility prior to the commercial operation date of the Wink to Webster pipeline system. The WWP Project Financing JV pledged the combined 30 percent interest in the Wink to Webster Pipeline JV contributed to it by MPLX and Delek to secure its obligations under the term loan facility.
On January 23, 2020, we announced the board of directors of our general partner had declared a distribution of $0.6875 per common unit that was paid on February 14, 2020 to common unitholders of record on February 4, 2020.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value through a review of its Midstream business and to analyze, among other things, the strategic fit of assets with MPC, the ability to realize full valuation credit for midstream earnings and cash flow, balance sheet impacts including liquidity and credit ratings, transaction tax impacts, separation costs, and overall complexity.
BUSINESS STRATEGIES
Our primary business objective is to enhance the generation of stable cash flows through executing the following strategies:
Capture Full Midstream Value Chain: We intend to develop incremental infrastructure to support growth across the hydrocarbon value chain. Touch points across the value chain include gathering, processing, fractionation, and inbound/outbound logistics assets such as long-haul pipelines and export facilities. This diversification and integration provide multiple sources of stable fee-based revenue while also enhancing opportunities for third-party revenue capture.
Enhance Cash Flow Stability: We are focused on growing our fee-based services through long-term contracts which provide through-cycle cash flow stability. Planned investments in long-haul pipelines are expected to connect supply to demand markets while adding a source of stable cash flow to the company and expanding our export capabilities will enhance our ability to meet significant growing market needs both domestically and globally.
Growth in Premier Basins: Our assets are located in some of the premier production areas in the United States. Our business strategy and investments are focused on connecting supply to global demand markets. We intend to increase operating cash flow by investing in opportunities that may arise in our areas of operations and increasing the utilization of our existing facilities. We will evaluate organic growth projects both within our geographic footprint as well as in new areas that we consider strategic.
Maintain Financial Discipline: We high-grade our portfolio of investment opportunities to ensure efficient deployment of capital focusing on mid-teen returns. Our goal is to optimize our cost of capital by maintaining an investment grade credit profile and funding our organic growth capital plan with operating cash and debt. The company does not intend to issue public equity to fund its organic growth capital needs.
Maintain Safe and Reliable Operations: We believe that providing safe, reliable and efficient services is a key component in generating stable cash flows. We are committed to maintaining and improving the safety, reliability and efficiency of our operations. Our intent is to continue promoting high standards for safety and environmental stewardship.
ORGANIZATIONAL STRUCTURE
The following diagram depicts our organizational structure and MPC’s ownership interest in us as of February 17, 2020.
We are an MLP with outstanding common units held by MPC and public unitholders as well as two series of preferred units. Our common units are publicly traded on the NYSE under the symbol “MPLX.” Our Series A preferred units rank senior to all common units and pari passu with our Series B preferred units with respect to distributions and rights upon liquidation. The holders of the Series A preferred units are entitled to receive a quarterly distribution equal to the greater of $0.528125 per unit or the amount of distributions they would have received on an as converted basis. The holders of the Series B preferred units are entitled to receive a fixed annual distribution equal to $68.75 per unit, per annum, payable semi-annually in arrears on February 15 and August 15, or the first business day thereafter, up to and including February 15, 2023. After February 15, 2023, the holders of Series B preferred units are entitled to receive cumulative, quarterly distributions payable in arrears on the 15th day of February, May, August and November of each year, or the first business day thereafter, based on a floating annual rate equal to the three-month LIBOR plus 4.652 percent.
INDUSTRY OVERVIEW
As of December 31, 2019, our diversified services in the midstream sector are across the hydrocarbon value chain. The types of services provided by the midstream sector, broken down by our segments, are as follows:
L&S:
The midstream sector plays a crucial role in the oil and gas industry by providing transportation, storage and marketing services across the hydrocarbon value chain as depicted below.
Crude oil is the primary raw material for transportation fuels and the basis for many products including plastics and petrochemicals, in addition to heating oil for homes once it is refined and prepared for use. Pipelines bring advantaged North American crude oil from the upper Great Plains, Louisiana, Texas, Canada and West Coast to numerous refineries throughout the United States. Terminals provide for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products via pipeline, rail, marine and over the road modes of transportation. This network of logistics infrastructure also allows for export opportunities by connecting supply to global demand markets. The hydrocarbon market is often volatile and the ability to take advantage of fast-moving market conditions is enhanced by the ability to store crude oil and other hydrocarbon-based products at tank farms, caverns, and tanks at refineries and terminals. The ability to store both crude and refined petroleum products provides flexibility and logistics optionality which allows participants within the industry to take advantage of changing market conditions.
G&P:
The midstream natural gas industry is the link between the exploration for, and production of, natural gas and the delivery of its hydrocarbon components to end-use markets. The components of this value chain are graphically depicted and further described below:
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Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, a network of pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems then transport raw, or untreated, natural gas to a central location for treating and processing.
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Processing. Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to as “y-grade”). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and commercial use.
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Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator.
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Storage, transportation and marketing. Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas is delivered to downstream transmission pipelines and NGL components are stored, transported and marketed to end-use markets.
Due to advances in well completion technology and horizontal drilling techniques, unconventional sources, such as shale and tight sand formations, have become a source of current and expected future natural gas production. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing/fractionating plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the shale plays will likely have a
competitive advantage. Well-positioned operations allow access to all major NGL markets and provide for the development of export solutions for producers. This proximity is enhanced by infrastructure build-out and pipeline projects.
OUR RELATIONSHIP WITH MPC
One of our competitive strengths is our strategic relationship with MPC, which, with its acquisition of Andeavor effective October 1, 2018, is the largest crude oil refiner in the United States in terms of refining capacity. MPC owns and operates 16 refineries in the West Coast, Gulf Coast and Mid-Continent regions of the United States and distributes refined products through transportation, storage, distribution and marketing services provided by its midstream segment, which primarily consists of MPLX. MPLX, through its fuels distribution services, distributes refined products under the Marathon brand through an extensive network of retail locations owned or operated by independent entrepreneurs, and through company owned and operated convenience stores across the United States, including under the Speedway brand.
MPC retains a significant interest in us through its non-economic ownership of our general partner and holding approximately 63 percent of the outstanding common units of MPLX as of December 31, 2019. Given MPC’s significant interest in us, we believe MPC will promote and support the successful execution of our business strategies.
OUR OPERATING SEGMENTS
We conduct our operations in two segments, which include L&S and G&P. As of December 31, 2019, our assets and operations in each of these segments are described below.
L&S:
The L&S segment includes transportation, storage and marketing of crude oil, refined products and other hydrocarbon-based products. These assets consist of a network of wholly and jointly-owned common carrier crude oil and refined product pipelines and associated storage assets, terminals, storage caverns, tank farm assets including rail and truck racks, an inland marine business, an export terminal and a fuels distribution business. Our pipeline network includes over 13,000 miles of pipeline throughout the continental United States and Alaska. Our storage caverns consist of butane, propane, and liquefied petroleum gas storage with a combined capacity of 4.7 million barrels located in Neal, West Virginia; Woodhaven, Michigan; Robinson, Illinois; and Jal, New Mexico. Our terminal facilities for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products are also located throughout the continental United States and Alaska, and have a combined total shell capacity of approximately 34 million barrels. We also own tank farm assets at certain MPC refineries in addition to stand-alone tank farms. Our network of terminals and refinery assets also includes rail and truck loading lanes/racks in addition to barge docks which support the transportation of hydrocarbon products via rail, over the road or marine. Our marine business owns and operates 23 boats and 286 barges, including third-party chartered equipment, and includes a Marine Repair Facility (“MRF”), which is a full-service marine shipyard located on the Ohio River adjacent to MPC’s Catlettsburg, Kentucky refinery. We also have ownership in various joint-interests, including LOOP LLC, the only U.S. deep-water oil port, located offshore of Louisiana, which is used to import and export crude oil. Additionally, our fuels distribution business provides MPC with a broad range of scheduling and marketing services. Our L&S assets are integral to the success of MPC’s operations. We continue to evaluate projects and opportunities that will further enhance our existing operations and provide valuable services to MPC and third parties. The following table summarizes projects and expansions that are expected to be completed in upcoming years.
We generate revenue in the L&S segment primarily by charging tariffs for crude gathering, transporting crude oil, refined products and other hydrocarbon-based products through our pipelines and at our barge docks delivering to domestic and international destinations, and fees for storing crude oil and refined products at our storage facilities. Our marine business generates revenue under a fee-for-capacity contract with MPC. Our fuels distribution business provides services related to the scheduling and marketing of products on behalf of MPC, for which it generates revenue based on the volume of MPC’s products sold each month while our wholesale business includes the operations of several bulk petroleum distribution plants and a fleet of refined product delivery trucks that distribute commercial wholesale petroleum products. We are also the operator of additional crude oil and refined product pipelines owned by MPC and third parties for which we are paid operating fees. For the year ended December 31, 2019, approximately 91 percent of L&S segment operating income was generated from MPC.
G&P:
We operate several natural gas gathering systems with the scope of gathering services that we provide dependent upon the producers need and the composition of the raw or untreated gas at our producer customers’ wellheads. For dry gas, we gather and, if necessary, treat the gas and deliver it to downstream transmission systems. For wet gas that contains heavier and more valuable hydrocarbons, we gather the gas for processing at a processing complex. Our natural gas processing complexes remove the heavier and more valuable hydrocarbon components from natural gas. This allows the residue gas remaining after extraction of the NGLs to meet the quality specifications for long-haul pipeline transportation or commercial use. The capacities of our gathering systems and processing complexes are supported by long-term, fee-based agreements with certain major producers and a number of these agreements include acreage dedications. Once natural gas has been processed at a natural gas processing complex, the heavier and more valuable hydrocarbon components, which have been extracted as a mixed NGL stream, can be further separated into their component parts through the process of fractionation. Our NGL fractionation facilities separate the mixture of extracted NGLs into individual purity product components for end-use sale. Our fractionation facilities for propane and heavier NGLs are also supported by long-term, fee-based agreements with certain major producers.
As a result of natural gas production, we recover ethane from the natural gas stream for certain producer customers, which allows them to meet residue gas pipeline quality specifications and downstream pipeline commitments. Depending on market conditions, producer customers may also benefit from the potential price uplift received from the sale of their ethane. We have connections to several downstream ethane pipelines from many of our systems that benefit our customers.
As production in geographic regions and market demand continues to evolve, so do our planned capital expenditures. The following table summarizes our properties that are expected to be constructed or have planned expansions in upcoming years. As of December 31, 2019, our gathering and processing assets include approximately 9.0 Bcf/d of gathering capacity, 11.6 Bcf/d of natural gas processing capacity and 831 mbpd of fractionation and stabilization capacity. For a summary of our gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines and natural gas pipelines see Item 2. Properties - Gathering and Processing.
(1)
This is a Sherwood Midstream LLC (“Sherwood Midstream”) investment. The first of six processing plants within this complex is scheduled to be in-service during 2020 with a processing capacity of 200 MMcf/d. The estimated completion dates for the five remaining plants are to be determined.
A significant portion of our business comes from a limited number of key customers. For the year ended December 31, 2019, revenues earned from two customers are significant to the segment, each accounting for approximately 14 percent of G&P operating revenues and six percent of consolidated operating revenues, respectively.
The following table summarizes our key producer customers and attributes for each geographic region:
(1)
We do not provide gathering services for these producer customers.
(2)
Region includes some contracts which contain acreage dedications.
For further financial information regarding our segments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Annual Report on Form 10-K.
OUR L&S CONTRACTS WITH MPC AND THIRD PARTIES
Transportation Services Agreements, Storage Services Agreements, Terminal Services Agreements and Fuels Distribution Services Agreement with MPC
Our L&S assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple transportation, terminal and storage services agreements with MPC. Under these long-term, fee-based agreements, we provide transportation, terminal and storage services to MPC and, other than under our marine transportation services agreement, most of these agreements include minimum committed volumes from MPC. MPC has also committed to provide a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation services agreement. We also have two fuels distribution agreements with MPC under which we provide scheduling and marketing services of MPC’s products.
The following table sets forth additional information regarding our transportation, terminal, fuels distribution, and storage services agreements with MPC:
(1)
Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, one to two additional five-year terms for our terminal services agreements, various renewal terms ranging from zero to 10 years for our cavern storage services agreements, various renewal terms ranging from one to five years for our tank farm storage services agreements, two additional five-year terms for our marine transportation services agreement and one additional five-year term for one of our two Fuels Distribution Services Agreements. These renewals are automatic, unless terminated by either party.
(2)
Commitments for our transportation services agreements refer to throughput in thousands of barrels per day and, for crude oil transportation services agreements, are adjusted for crude viscosities. Commitments for our cavern storage services agreements refer to thousands of barrels. Commitments for our terminal services agreements refer to quarterly terminal throughput or stipulated volumes in thousands of barrels. Commitments for the fuels distribution services agreements refers to millions of gallons per year. Minimum commitments on some agreements are reduced by any third-party throughput volumes.
(3)
MPC has committed to utilize 100 percent of our available capacity of boats and barges.
(4)
Volume shown represents total capacity in thousands of barrels (includes refining logistics tanks).
(5)
Some terminal services agreements also contain minimum commitments for activities such as blending, additives, on-loading and off-loading, and storage.
Under transportation services agreements containing minimum volume commitments, if MPC fails to transport its minimum throughput volumes during any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. Under these transportation services agreements, the amount of any deficiency payment paid by MPC may be applied as a credit for any volumes transported on the applicable pipeline in excess of MPC’s minimum volume commitment during a limited number of succeeding periods, after which time any unused credits will expire.
We have crude oil and asphalt trucking transportation services agreements with MPC. Under these trucking transportation services agreements, we receive a service fee per barrel for gathering barrels and providing trucking, dispatch, delivery and data services. Under some of our trucking transportation agreements, if MPC fails to request the minimum volume commitment to be gathered and delivered, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the trucking rate then in effect.
Under most of our terminal services agreements, if MPC fails to meet its minimum volume commitment during any period, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. Some of our terminal services agreements contain minimum commitments for various additional services such as storage and blending.
We have a fuels distribution service agreement with MPC in which MPC pays MPLX a tiered monthly fee based on the volume of MPC’s products sold by MPLX each month, subject to a maximum annual volume. MPLX has agreed to use commercially reasonable efforts to sell not less than a minimum quarterly volume of MPC’s products during each calendar quarter. If MPLX sells less than the minimum quarterly volume of MPC’s products during any calendar quarter despite its commercially reasonable efforts, MPC will pay MPLX a deficiency payment equal to the volume deficiency multiplied by the applicable tiered fee. The
dollar amount of actual sales volume of MPC’s products that exceeds the minimum quarterly volume (an “Excess Sale”) for a particular quarter will be applied as a credit, on a first-in-first-out basis, against any future deficiency payment owed by MPC to MPLX during the four calendar quarters immediately following the calendar quarter in which the Excess Sale occurs. Additionally, we have a wholesale fuels distribution services agreement as a result of the Merger, under which we are required to sell and deliver product to MPC, and MPC is required to purchase and accept delivery of product from us. MPC pays us an amount equal to our product cost at each terminal, plus applicable taxes and fees, actual transportation cost and a contracted margin. In the event that MPC fails to purchase the committed volume, MPC pays an agreed upon amount for each gallon below the committed volume and will receive a credit for excess volumes purchased in subsequent months to the extent that shortfall payment were made in the prior twelve months. MPC also provides us margin shortfall support for non-delivered rack sales.
Pipeline Operating Agreements with MPC
We operate various pipelines owned by MPC under operating services agreements. Under these operating services agreements, we receive an operating fee for operating the assets, which include certain MPC wholly-owned or partially-owned crude oil, natural gas, and refined product pipelines, and for providing various operational services with respect to those assets. We are generally reimbursed for all direct and indirect costs associated with operating the assets and providing such operational services. These agreements vary in length and automatically renew with most agreements being indexed for inflation.
Pipeline Operating Agreements with Third Parties
We maintain and operate five joint interest pipelines including Andeavor Logistics Rio Pipeline LLC, Capline Pipeline Company LLC, Centennial Pipeline LLC, Louisville-Lexington Operation and Muskegon Pipeline LLC. We receive an operating fee for each of these pipelines, which is subject to adjustment for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline. The length and renewal terms for each agreement vary.
Terminal Services Agreements with Third Parties
We have multiple terminal services agreements with third parties under which we provide use of pipelines and tank storage, and provide services, facilities and other infrastructure related to the receipt, storage, throughput, blending and delivery of commodities. Some of these agreements are subject to prepaid throughput volumes under which we agree to handle a certain amount of product throughput each month in exchange for a predetermined fixed fee, with any excess throughput or ancillary services subject to additional charges. Under the remaining agreements we receive an agreed upon fee based on actual product throughput following the completion of services.
Management Services Agreement with MPC
MPLX has a management services agreement with MPC under which it provides management services to assist MPC in the oversight and management of the marine business. MPLX receives a fixed annual fee for providing the required management services. This fee is adjusted annually on the anniversary of the contract for inflation and any changes in the scope of the management services provided. This agreement is set to expire on January 1, 2021 and automatically renews for two additional renewal terms of five years each unless terminated by either party.
Other Agreements with MPC
We have omnibus agreements with MPC that address our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain services to us, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we indemnify MPC for certain matters under these agreements.
We also have various employee services agreements and a secondment agreement under which we reimburse MPC for the provision of certain operational and management services to us. All of the employees that conduct our business are directly employed by affiliates of our general partner.
Additionally, we have certain indemnification agreements with MPC under which MPC retains responsibility for remediation of known environmental liabilities due to the use or operation of the assets prior to our ownership, and indemnifies us for any losses we incurred arising out of those remediation obligations. The indemnification for unknown pre-closing remediation liabilities is generally limited to five years.
OUR G&P CONTRACTS WITH MPC AND THIRD PARTIES
The majority of our revenues in the G&P segment are generated from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. MPLX enters into a variety of contract types including fee-based, percent-of-proceeds, keep-whole and purchase arrangements in order to generate service revenue and product sales. See Item 8. Financial Statements and Supplementary Data - Note 2 for a further description of these different types of arrangements.
In many cases, MPLX provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of MPLX’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. In addition, minimum volume commitments may create contract liabilities or deferred credits if current period payments can be used for future services. Breakage is estimated and recognized into service revenue in instances where it is probable the customer will not use the credit in future periods.
MPLX’s contract mix and exposure to natural gas and NGL prices may change as a result of changes in producer preferences, MPLX expansion in regions where some types of contracts are more common and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.
Keep-whole agreement with MPC
MPLX has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGL’s related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. The pricing structure under this agreement provides for a base volume subject to a base rate and incremental volumes subject to variable rates, which are calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes are subject to revision each year. This agreement renews automatically on a year-to-year basis, unless terminated by either party.
COMPETITION
Within our L&S segment, our competition primarily comes from independent terminal and pipeline companies, integrated petroleum companies, refining and marketing companies, distribution companies with marketing and trading arms and from other wholesale petroleum products distributors. Competition in any particular geographic area is affected significantly by the volume of products produced by refineries in the area, and in areas where no refinery is present, by the availability of products and the cost of transportation to the area from other locations.
As a result of our contractual relationship with MPC under our transportation and storage services agreements, our terminal services agreement, and our physical asset connections to MPC’s refineries and terminals, we believe that MPC will continue to utilize our assets for transportation, storage, distribution and marketing services. If MPC’s customers reduced their purchases of refined products from MPC due to increased availability of less expensive refined product from other suppliers or for other reasons, MPC may only receive or deliver the minimum volumes through our terminals (or pay the shortfall payment if it does not deliver the minimum volumes), which could decrease our revenues.
In our G&P segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability, and the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.
Our competitors include:
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natural gas midstream providers, of varying financial resources and experience, that gather, transport, process, fractionate, store and market natural gas and NGLs;
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major integrated oil companies and refineries;
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independent exploration and production companies;
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interstate and intrastate pipelines; and
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other marine and land-based transporters of natural gas and NGLs.
Some of our competitors operate as MLPs or are owned by infrastructure funds and may enjoy a cost of capital comparable to and, in some cases, lower than ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.
We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements, allows us to compete more effectively. This includes having access to both NGL and natural gas markets to allow for flexibility in our gathering and processing in addition to having critical connections to a strong sponsor and key market outlets for NGLs and natural gas. Our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of our resource plays. The strategic location of our assets, including those connected to MPC, and the long-term nature of many of our contracts also provide a significant competitive advantage.
INSURANCE
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and business interruption. We are insured under MPC and other third-party insurance policies. The MPC policies are subject to shared deductibles.
SEASONALITY
The volume of crude oil and refined products transported and stored utilizing our assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Many effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments.
Our G&P segment can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors including variations in weather patterns from year to year. We are able to manage the seasonality impacts through the execution of our marketing strategy and via our storage capabilities. Overall, our exposure to the seasonality fluctuations is declining due to our growth in fee-based business.
REGULATORY MATTERS
Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations or to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and other costs to MPLX. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. The following is a summary of some of the environmental, health and safety laws and regulations to which our operations are subject.
Pipeline Regulations
Common Carrier Liquids Pipeline Operations.
We have liquids pipelines that are common carriers subject to regulation by various federal, state and local agencies. FERC regulates interstate transportation on liquids pipelines under the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate pipelines that transport crude oil, NGLs (including purity ethane) and refined petroleum products (collectively referred to as “petroleum pipelines”), be just and reasonable and the terms and conditions of service must not be unduly discriminatory or confer any undue preference upon any shipper.
The ICA requires that interstate petroleum pipeline transportation rates and terms and conditions of service be filed with the governing agency, which is FERC, and posted publicly. Under the ICA, persons with a substantial economic interest in a petroleum pipeline’s rate or service may challenge that rate or service before FERC. FERC is authorized to investigate such challenges and may suspend the effectiveness of a newly filed rate or term or condition of service for up to seven months. A successful protest to a new rate or term of condition of service could result in a petroleum pipeline paying refunds, together with interest, for the period that the rate or term or condition of service was in effect. A successful protest could also result in FERC disallowing the rate or service. A successful complaint to an existing rate or service could result in a petroleum pipeline paying reparations, together with interest, for the period beginning two years prior to the date of the filing of the complaint until the just and reasonable rate or service was established. FERC may also investigate, upon complaint, protest, or on its own motion, newly proposed rates and terms of service, existing rates and related rules, and may order a pipeline to change them prospectively or may bar a pipeline from implementing the proposed new or changed rates or terms of service.
EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Our rates for interstate transportation service in effect for the 365-day period ending on the date of the passage of EPAct 1992 were deemed just and reasonable and therefore are grandfathered. Subsequent changes to those rates are not grandfathered. New rates have since been established after EPAct 1992 for certain pipelines, and the rates for certain of our refined products pipelines have subsequently been approved as market-based rates.
EPAct 1992 required FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, FERC adopted an indexed rate methodology which, as currently in effect, allows petroleum pipelines to change their rates within prescribed ceiling levels that are tied to annual changes in the producer price index-finished goods (“PPI-FG”). FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2016 and ending June 30, 2021, petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by the change in the PPI-FG plus an adder that is currently set at 1.23 percent. The current adder will be in effect until June 30, 2021 or until revised by a formal rulemaking by FERC. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates and settlement rates (unless permitted under the settlement). A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so, and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s costs. However, FERC is currently evaluating how indexed adjustments to rates can be challenged as well as how pipelines must demonstrate their annual costs and incomes. Therefore, we cannot guarantee FERC will not make changes to its current policy regarding challenges in the future. Under the indexing rate methodology, in any year in which the index is negative, a pipeline must lower the rate ceiling and file to lower rates if any of the pipelines’ rates would otherwise be above the new rate ceiling, unless the pipeline makes a filing attesting that all shippers that pay the rate have approved the pipeline not lowering the rate or the pipeline can demonstrate substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index.
While petroleum pipelines often use the indexing methodology to change their rates, petroleum pipelines may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. At various times, we have used index rates, settlement rates and market-based rates to change the rates for our different FERC-regulated petroleum pipelines.
FERC issued a policy statement in May 2005 stating that it would permit interstate petroleum pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s 2005 policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. FERC’s 2005 income tax policy was the subject of various appeals by shippers, before FERC and the courts, and United States Court of Appeals for the District of Columbia Circuit issued a ruling that remanded a case related to pass-through entities and the income tax allowance back to FERC for further review and consideration. In response, FERC issued a Revised Policy Statement on the Treatment of Income Taxes on March 15, 2018 indicating, among other things, that interstate petroleum pipelines held by master limited partnerships would no longer be allowed to recover an income tax allowance in cost-of-service rates. This particular matter is currently in briefing before the United States Court of Appeals for the District of Columbia Circuit, and we cannot guarantee that FERC or the courts will not make changes to the policy in the future.
Intrastate services provided by certain of our liquids pipelines are subject to regulation by state regulatory authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. Not all state regulatory bodies allow for changes based on an index method similar to that used by FERC. In those instances, rates are generally changed only through a rate case process. The state regulators could limit our
ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could, if permitted under state law, require the payment of refunds to shippers.
FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates are not the subject of a protest or a complaint by a shipper. MPC has agreed not to contest our tariff rates for the term of our transportation and storage services agreements with MPC, but we do not have any of these types of agreements with third parties. FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in our tariff rate level.
If our rate levels were investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs.
If FERC or a state commission were to determine that our rates were or had become unjust and unreasonable, we could be ordered to reduce rates prospectively and pay refunds and/or reparations to shippers.
FERC-Regulated Natural Gas Pipelines.
Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, we have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and MarkWest Pioneer, L.L.C., with respect to our Hobbs Pipeline and the Arkoma Connector Pipeline. In addition, gas tariffs are on file for Rendezvous Pipeline Company LLC, which moves gas into Kern River Transmission. Additionally, we have ownership interests in joint ventures with FERC gas tariffs on file.
Under the Natural Gas Act (“NGA”), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable, or unduly discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. The rates and terms and conditions for the Hobbs Pipeline and the Arkoma Connector Pipeline can be found in their respective FERC-approved tariffs and in negotiated rate agreements entered into under those tariffs. Rendezvous Pipeline Company has authority to charge market-based rates, and its tariffs and pertinent operational information can be found on its website. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases proposed by the pipeline or other tariff changes may be challenged (e.g., by protest). We also cannot be assured that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules, rights of access, capacity and other issues that impact natural gas facilities. Any successful complaint or protest related to our services or facilities could have an adverse impact on our revenues.
Energy Policy Act of 2005.
On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”). Under the 2005 EPAct, FERC may impose civil penalties for violations of statutory and regulatory requirements. The 2005 EPAct also amends the NGA to add an anti-market manipulation provision, which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. FERC issued Order No. 670 to implement the anti-market manipulation provision of the 2005 EPAct. This order makes it unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, use or employ any device, scheme or artifice to defraud in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The
anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority.
Standards of Conduct.
FERC has adopted affiliate standards of conduct applicable to interstate natural gas pipelines and certain other regulated entities, defined as “Transmission Providers.” Under these rules, a Transmission Provider becomes subject to the standards of conduct if it provides service to affiliates that engage in marketing functions (as defined in the standards). If a Transmission Provider is subject to the standards of conduct, the Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). The Transmission Provider must also comply with certain posting and other requirements.
Intrastate Natural Gas Pipeline Regulation.
Some of our intrastate gas pipeline facilities are subject to various state laws and regulations that affect the rates we charge and terms of service. Although state regulation is typically less onerous than FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC’s jurisdiction. We are subject to such regulations and reporting requirements to the extent that any of our intrastate pipelines provide, or are found to provide, such interstate services.
Additional proposals and proceedings that might affect the natural gas industry periodically arise before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than other midstream natural gas companies with whom we compete.
Natural Gas Gathering Pipeline Regulation.
Section 1(b) of the NGA exempts natural gas production and gathering from the jurisdiction of FERC. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Rather, FERC looks at a number of factors, including length and diameter of pipeline facilities, extension beyond the central point of the field, geographic configuration, location of compressors and processing plants, location of wells along all or part of the facility and operating pressure of the facilities. We own a number of facilities that we believe qualify as production and gathering facilities not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, potentially provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC reporting requirements.
In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, non-discriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.
Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.
Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 Code of Federal Regulations (“C.F.R.”) Part 192, which governs construction standards and operation of certain natural gas gathering pipelines. The changes that have been proposed include, but are not limited to, more stringent construction standards for remote facilities, as well as additional record-keeping requirements. Depending upon the nature of the final rule-making, those could have an impact upon MPLX LP operations. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.
Natural Gas Processing.
Our natural gas processing operations are not presently subject to FERC or state rate regulation. There can be no assurance that our processing operations will continue to be exempt from rate regulation in the future. In addition, although the processing facilities may not be directly related, other laws and regulations may affect the availability of natural gas for processing, such as state regulation of production rates and maximum daily production allowances from gas wells, which could impact our processing business.
NGL Pipelines.
We have constructed various NGL product pipelines to transport NGL products, some of which are regulated by FERC, and we may elect to construct additional such pipelines in the future that may be subject to these same regulatory requirements. Pipelines providing transportation of NGLs in interstate commerce are subject to the same regulatory requirements as common carrier petroleum pipelines. See “Common Carrier Liquids Pipeline Operations” above.
Our NGL pipelines are also subject to safety regulation by the DOT under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines. In October 2019, PHMSA finalized rulemaking reviewing the scope and applicability of 49 C.F.R. Part 195, including, among other things, expansion of reporting obligations, additional inspection requirements, emergency order authority, expansion of integrity management principles and expansion of the use of leak detection systems. These changes became effective in 2020 and could have an impact upon MPLX LP and other pipeline operators. Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.
Propane Regulation.
National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies and in others they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the DOT. We conduct ongoing training programs to help ensure that our operations comply with applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our propane operations. We believe that the procedures currently in effect at all of our facilities for the
handling, storage and distribution of propane are consistent with industry standards and comply in all material respects with applicable laws and regulations.
Marine Transportation.
Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act, state laws and certain international conventions, as well as numerous environmental regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels.
Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage law that restricts domestic marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones Act for our vessels. The loss of Jones Act status could have a significant negative effect on us. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the USCG, and the application of United States labor and tax laws increases the cost of United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that is not subject to the same United States government imposed burdens. Since the events of September 11, 2001, the United States government has taken steps to increase security of United States ports, coastal waters and inland waterways. We believe that it is unlikely that the current cabotage provisions of the Jones Act would be modified or eliminated in the foreseeable future.
The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is necessary in the interest of national defense. For example, the Secretary has waived the Jones Act generally or with respect to the transportation of certain petroleum products for limited periods of time and in limited areas following the occurrence of certain natural disasters such as hurricanes. Waivers of the Jones Act, whether in response to natural disasters or otherwise, could result in increased competition from foreign tank vessel operators, which could negatively impact our marine transportation business.
Pipeline Interconnections.
One or more of our plants include pipeline interconnections to, or incidental gathering pipelines that connect the plants to, interstate pipelines. These pipeline interconnections are an integral part of our facilities and are not currently being used, nor can they be used in the future, by any third party due to their origin points at our proprietary facilities. Therefore, we believe these pipeline interconnections are part of our plant facilities and are not subject to the jurisdiction of FERC. In the event that FERC were to determine that these pipeline interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a waiver from most FERC reporting and filing requirements. In the event that FERC were to determine that the pipeline interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC for the pipeline interconnections, provide a cost justification for their transportation rates and provide service to all potential shippers without undue discrimination. In such event, we may experience increased operating costs and reduced revenues.
Security.
Certain of our facilities have been preliminarily classified as subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” The Transportation Security Administration Security Guidelines are subject to change without formal regulatory proposal and review. We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.
ENVIRONMENTAL REGULATION
Our management is responsible for ensuring that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations, and for reviewing our overall environmental performance. We also have a Corporate Emergency Response Team that oversees our response to any major environmental or other emergency incident involving us or any of our facilities.
We believe it is likely that the scientific and political attention to greenhouse gas emissions, climate change and climate adaptation will continue, with the potential for further regulations that could affect our operations. Currently, legislative and regulatory measures to address greenhouse gas emissions are in various phases of review, discussion or implementation. The cost to comply with these laws and regulations cannot be estimated at this time, but could be significant. For additional information, see Item 1A.
Item 1A. Risk Factors
You should carefully consider each of the following risks and all the other information contained in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business, the business and operations of MPC and the industry in which we operate, while others relate principally to tax matters, ownership of our common units and the securities markets generally.
Our business, financial condition, results of operations or cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline.
Risks Relating to Our Business
Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flow, and our ability to fulfill our debt obligations.
We have significant debt obligations, which totaled $20.7 billion as of December 31, 2019. We may incur significant debt obligations in the future, including under our loan agreement with MPC. Our existing and
future indebtedness may impose various restrictions and covenants on us that could have, or the incurrence of such debt could otherwise result in, material adverse consequences, including:
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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.
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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.
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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.
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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.
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If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.
A significant decrease in oil and natural gas production in our areas of operation, whether due to sustained declines in oil, natural gas and NGL prices, natural declines in well production, or otherwise, may adversely affect our revenues, financial condition, and cash available for distribution.
A significant portion of our operations is dependent on the continued availability of natural gas and crude oil production. The production from oil and natural gas reserves and wells owned by our producer customers will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually obtain new oil, natural gas, NGL and refined product supplies, which depend in part on the level of successful drilling activity near our facilities, our ability to compete for volumes from successful new wells and our ability to expand our system capacity as needed.
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, among other things, prevailing and projected energy prices, drilling costs per mcf or barrel, demand for hydrocarbons, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Because of these factors, even if oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. 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 also significantly curtailing or limiting their oil and gas drilling operations which could substantially delay the production and delivery of volumes of oil, 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 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 gas or NGL prices due to the potential difference in the time of the purchases and sales and the potential difference in the price associated with each transaction, and direct exposure may also occur naturally as a result of our production processes. The significant volatility in natural gas, NGL and oil prices could adversely impact our unit price, thereby increasing our distribution yield and cost of capital. Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy our obligations to our customers, and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.
We may not 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 minimum quarterly distribution to our unitholders.
We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution to our unitholders. The amount of cash we can distribute on our common units depends principally on the amount of cash we generate from our operations, which may fluctuate from quarter to quarter based on, among other things:
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the fees and tariff rates we charge and the margins we realize for our services and sales;
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the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;
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the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;
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the level of our operating costs including repairs and maintenance;
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the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and
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prevailing economic conditions.
In addition, the actual amount of cash available for distribution may depend on other factors, some of which are beyond our control, including:
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the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC in respect of those expenses;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets;
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restrictions in our joint venture agreements, revolving credit facility or other agreements governing our debt;
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the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;
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the cost of acquisitions, if any; and
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the amount of cash reserves established by our general partner in its discretion.
In an effort to fund a greater portion of our organic growth with retained cash, the amount of cash reserves established by our general partner may increase in the future, which in turn may 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.
The number of our outstanding common units has increased significantly, and we have outstanding an additional class of preferred units as a result of the Merger, which could make it more difficult for us to pay the current level of quarterly distributions.
We issued approximately 263 million common units in connection with the Merger. Accordingly, the aggregate dollar amount required to pay the quarterly distribution on all our common units has increased, which could increase the likelihood that we will not have sufficient funds to pay the current level of quarterly distributions to all unitholders.
Further, we issued 600,000 new Series B preferred units in the Merger. We must pay distributions that have accrued on the Series A preferred units and the new Series B preferred units prior to paying any distributions on our common units. Distributions are payable on the Series A preferred units at a rate of the greater of $0.528125 per quarter per Series A preferred unit or the quarterly distribution that the holder would have received with respect to common units on an as-converted basis. The requirement to pay distributions on the new Series B preferred units increases the likelihood that we will not have sufficient funds to pay the current level of distributions to our common unitholders following the completion of the Merger.
Global economic conditions may have adverse impacts on our business and financial condition.
Changes in economic conditions could adversely affect our financial condition and results of operations. A number of economic factors, including gross domestic product, consumer interest rates, government spending, consumer confidence and debt levels, retail trends, inflation, tariffs, trade agreements and foreign currency exchange rates, may generally affect our business. Recessionary economic cycles, higher unemployment rates, higher fuel and other energy costs, higher tax rates and global outbreaks of infectious diseases, such as the coronavirus first detected in Wuhan, China, may adversely affect demand for natural gas, NGLs and crude oil. Also, any tightening of the capital markets could adversely impact our ability to execute our long-term organic growth projects and meet our obligations to our customers and limit our ability to raise capital and, therefore, have an adverse impact on our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on our common units.
Our investments in joint ventures decrease our ability to manage risk.
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 business, financial condition, results of operations and cash flows.
Our expansion of existing assets and the construction of new assets will be subject to regulatory, environmental, political, legal and economic risks that could adversely impact our business, financial condition, results of operations and cash flows.
One of the ways we intend to grow our business is through the construction of, or additions to, our existing gathering, transportation, treating, processing, storage and fractionation facilities. We may also grow our business by constructing new pipelines or expanding existing pipelines by adding horsepower or pump stations or by adding additional pipelines along existing pipelines. Such construction requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political and legal uncertainties, most of which are beyond are control. Factors beyond our control include delays caused by third-party landowners, unavailability of materials, labor shortages or disruptions, environmental constraints, financing, accidents, weather and other factors. Additionally, we are subject to numerous regulatory, environmental, political, legal and inflationary uncertainties, including societal sentiment regarding the development and use of carbon-based fuels,
political pressures and the influence of environmental or other special interest groups, as well as stringent and lengthy federal, state and local permitting, zoning, consent, or authorizations requirements, or new laws, regulations, requirements or enforcement actions, which may cause us to incur additional capital expenditures, delay, interfere with or impair our construction activities, including by requiring the redesign of facilities, the acquisition of additional equipment, and relocations or rerouting of facilities, and subject us to additional expenses or penalties and adversely affect our operations and cash flows available for distribution to unitholders. 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. If we undertake these projects, we may not be able to complete them 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.
For example, certain of our processing, fractionation and pipeline facilities are located in mountainous areas such as our Utica, Marcellus and southern Appalachian operations, which may require specially designed foundations, retaining walls and other structures or facilities. If such foundations, retaining walls or other facilities are not designed or installed correctly, do not perform as intended or fail, we may be required to incur significant capital expenditures to correct or repair the deficiencies, or may incur significant damage to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damages to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines. In addition, certain agreements with our customers contain substantial financial penalties or give the producer the right to repurchase certain assets and terminate their contracts with us if construction deadlines are not achieved. Any such penalty or contract termination could have a material adverse effect on our income from operations and cash available for distribution.
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 may 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.
We may not always be able to accurately estimate hydrocarbon reserves and expected production volumes; therefore, volumes we service in the future could be less than we anticipate.
We work closely with our producer customers in an effort to understand hydrocarbon reserves and expected production volumes. We periodically review or have outside consultants review hydrocarbon reserve information and expected production data that is publicly available or that is provided to us by our producer customers. However, we may not be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a variety of reasons, including the unavailability of sufficiently detailed information and unanticipated changes in producers’ expected drilling schedules. Accordingly, we may not have accurate estimates of total reserves serviced by our assets, the anticipated life of such reserves or the expected volumes to be produced from those reserves.
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. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough oil, natural gas, NGLs or refined products to achieve our
expected investment return or result in immediate revenue increases, which could adversely affect our operations and cash available for distribution. 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 increase 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 engage in commodity derivative activities to mitigate the impact of commodity price volatility on our cash flows, but these activities may reduce our earnings, profitability and cash flows. In addition, we may not accurately predict future commodity price fluctuations, our risk management activities may impair our ability to benefit from price increases, and additional regulation of commodity derivative activities could adversely impact our ability to manage these risks.
Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.
The extent of our commodity price exposure is related largely to our contract mix and the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements that are subject to commodity price volatility and, as a result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial instruments, including the extension of the settlement date of such instruments. Additionally, because we may use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect and our risk management policies and procedures are not properly followed. For further information about our risk management policies and procedures, please read Item 8. Financial Statements and Supplementary Data - Note 16.
To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk and commodity prices move adversely, we could suffer losses. Such losses could be substantial and could adversely affect our operations and cash flows available for distribution. In addition, managing the commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.
As a result of the Dodd-Frank Act, OTC derivatives markets and entities are subject to regulation by the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions that are or become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements. Although we believe that we qualify for the end-user exception to the mandatory clearing requirements for swaps to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants may change the cost and availability of the swaps that we use for hedging. Additional mandatory clearing requirements could be imposed that may impair our ability to maintain OTC hedging positions or require us to post collateral. The Dodd-Frank Act and its implementing regulations, including those not yet finalized, could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we
encounter, reduce our ability to monetize or restructure our existing derivative contracts, increase the administrative burden and regulatory risk associated with entering into certain derivative contracts, and increase our exposure to less credit-worthy counterparties. As a result, if we reduce our use of derivatives, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our income from operations and cash flows available for distribution.
Due to an increased domestic supply of NGLs, we may be required to find alternative NGL market outlets and to rely more heavily on the export of NGLs, which may increase our operating costs or reduce the price received for NGLs and thereby reduce our cash available for distribution.
Due to increased production of natural gas, particularly in shale plays, there is an increased domestic supply of NGLs, which is currently outpacing, and could continue to outpace, domestic demand. As a result, we and our producer customers may need to continue to find alternate NGL market outlets and to rely more heavily on the export of NGLs. Our ability to find alternative NGL market outlets is dependent upon a variety of factors, including the construction and installation of additional NGL transportation infrastructure necessary to transport NGLs to other markets. In order to obtain committed transportation capacity, it may be necessary to make significant minimum volume commitments, with take or pay payments or deficiency fees if the minimum volume is not delivered. In other instances, we may enter into long-term sales arrangements, and we may incur shortfall or deficiency fees or be subject to other liabilities, including breach of contract claims, if we do not deliver the contracted quantity. We market NGLs on behalf of certain of our producer customers, and as a result, we may make such commitments on behalf of those producer customers. We expect to be able to pass such commitments through to our producer customers, but if we were unable to do so, our operating costs may increase significantly, which could have a material adverse effect on our results of operations and our ability to make cash distributions. Certain of our producer customers have elected, or may from time to time in the future elect, to take in kind and market their NGLs directly, which may also impact our ability to meet any obligations we may have to deliver contracted quantities of NGLs or other commitments. Similarly, our ability to export NGLs on a competitive basis is impacted by various factors, including:
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availability of sufficient railcar, tanker and terminalling facility capacity;
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currency fluctuations;
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compliance with additional governmental regulations and maritime requirements, including U.S. export controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;
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risks of loss resulting from non-payment or non-performance by international purchasers; and
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political and economic disturbances in the countries to which NGLs are being exported.
The above factors could increase our operating costs or adversely affect the price that we and our producer customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income and cash available for distribution.
We depend on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.
A significant portion of our supply of oil, natural gas, refinery off-gas, NGLs and refined products comes from a limited number of key producers/suppliers, who may be under no obligation to deliver a specific volume to our facilities. If any of these significant suppliers, or a significant number of smaller producers, were to decrease the supply of oil, natural gas, refinery off-gas, NGLs or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural gas, refinery off-gas, NGLs or refined products to our facilities or we rely on other third parties to deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation
systems or the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow.
We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.
A significant portion of our business comes from a limited number of key customers. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines and fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new customers that we cannot provide. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services.
As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability.
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.
We are exposed to the credit risks of our key customers and derivative counterparties, and any material non-payment or non-performance by our key customers or derivative counterparties could reduce our ability to make distributions to our unitholders.
We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. This risk is further heightened during sustained periods of declines of
natural gas, NGL and oil prices. With respect to our producer customers who have made acreage dedications to us, we may be exposed to additional risks to the extent that those customers become bankrupt and the acreage dedications are challenged and not upheld in bankruptcy. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any such material non-payment or non-performance could reduce our ability to make distributions to our unitholders.
We are indemnified for certain environmental liabilities arising from properties on which certain of our facilities are located and our results of operations and our ability to make distributions to our unitholders could be adversely affected if an indemnifying party fails to perform its indemnification obligations.
Prior third-party owners or operators of certain of our facilities, or such parties’ successors-in-interest, have in certain circumstances agreed to retain full or partial liability and responsibility for, or to indemnify us against, any environmental liabilities associated with these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased and to the extent not contributed to by us. Our results of operations and our ability to make cash distributions to our unitholders could be adversely affected if in the future any of these third parties fail to perform their indemnification obligations. In addition, from time to time, we have acquired, and may acquire in the future, facilities from third parties which previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. In some cases, we may receive indemnification from the prior owner or operator for some or all of such liabilities, and in other cases we may accept some or all of such liabilities. There is no assurance that any such third parties will perform any such indemnification obligations, or that the obligations and liabilities that we may accept in connection with any such acquisition will not be larger than anticipated, and in such event, our results of operations and cash available for distribution could be adversely affected.
Our operations could be disrupted if we are unable to maintain or obtain real property rights required for our business.
We do not own all of the land on which our assets are located, but rather obtain the rights to construct and operate such assets on land owned by third parties and governmental agencies for a specific period of time. Therefore, we are subject to the possibility of more burdensome terms and increased costs to retain necessary land use if our leases, rights-of-way or other property rights lapse, terminate or are reduced or it is determined that we do not have valid leases, rights-of-way or other property rights. Any loss of or reduction in these rights, including loss or reduction due to legal, governmental or other actions or difficulty renewing leases, right-of-way agreements or permits on satisfactory terms or at all, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.
Certain of our facilities are located on Native American tribal lands and are subject to various federal and tribal approvals and regulations, which may increase our costs and delay or prevent our efforts to conduct planned operations.
Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, Bureau of Land Management, and the Office of Natural Resources Revenue, along with each Native American tribe, regulate natural gas and oil operations on Native American tribal lands, including drilling and production requirements and environmental standards. 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.
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.
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, including but not limited to, explosions, fires, pipeline releases, cybersecurity breaches or other incidents involving our assets or operations, could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain insurance of the types and amounts we desire at reasonable rates.
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.
Risks Relating to Strategic Transactions
MPC’s ongoing review of strategic alternatives for its midstream business could materially impact our strategic direction, business and results of operations.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value through a review of its Midstream business, of which MPLX is the primary component. MPC’s exploration of strategic alternatives, including any uncertainty created by this process, involves a number of risks: significant fluctuations in our unit price could occur in response to developments or actions relating to the strategic review process or market speculation regarding any such developments or actions; we may encounter difficulties in hiring, retaining and motivating key personnel who provide services to us during this process or as a result of uncertainties generated by this process or any developments or actions relating to it; we may incur substantial increases in general and administrative expense associated with increased legal fees and the need to retain and compensate third-party advisors; and we may experience difficulties in preserving the commercially sensitive information that may need to be disclosed to third parties during this process or in connection with an assessment of our strategic alternatives. The strategic review process also requires significant time and attention from management, which could distract them from other tasks in operating our business. There can be no assurance that this process will result in the pursuit or consummation of any strategic transaction. The occurrence of any one or more of the above risks could have a material adverse impact on our business, financial condition, results of operations and cash flows.
The Merger may not be accretive, and may be dilutive, to our earnings per unit, which may negatively affect the market price of our common units.
In connection with the completion of the Merger, we issued approximately 263 million common units. Any dilution of, or delay of any accretion to, our earnings per unit could cause the price of our common units to decline or increase at a reduced rate.
We have incurred and will continue to incur significant transaction and Merger-related costs in connection with the Merger, which may be in excess of those anticipated by us.
We have incurred substantial expenses in connection with the Merger. We expect to continue to incur transaction fees and costs related to formulating and implementing integration plans, including facilities and systems consolidation costs. These fees and costs have been, and may continue to be, substantial.
Additional unanticipated costs may be incurred in the integration of the two partnerships’ businesses. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, may not be sufficient to allow us to offset integration-related costs over time. These integration costs, as well as other unanticipated costs and expenses, could have a material adverse effect on our financial condition and operating results.
We may fail to realize all of the anticipated benefits of the Merger.
The success of the Merger depends, in part, on our ability to realize the anticipated benefits and cost savings from combining MPLX’s and ANDX’s businesses. The anticipated benefits and cost savings of the Merger may not be realized fully or at all, or may take longer to realize than expected or could have other adverse effects that we do not currently foresee. Some of the assumptions that we have made, such as the achievement of operating synergies and the expansion in opportunities for logistics growth in crude oil production basins and regions, may not be realized. The integration process may result in the loss of key personnel who provide services to the two partnerships, the disruption of ongoing businesses or inconsistencies in standards, controls, procedures and policies. There could be potential unknown liabilities and unforeseen expenses associated with the Merger that were not discovered in the course of performing due diligence.
The combined partnership recorded goodwill and other intangible assets that could become impaired and result in material non-cash charges to the results of operations of the combined partnership in the future.
The Merger was accounted for as a reorganization of entities under common control in accordance with accounting principles generally accepted in the United States. Under a reorganization of entities under common control, the assets and liabilities of ANDX transferred between entities under common control were recorded by MPLX based on MPC’s historical cost basis resulting from its preliminary purchase price accounting. We recorded ANDX’s assets and liabilities at MPC’s basis as of October 1, 2018, the date that common control was first established.
Effective October 1, 2018, MPC acquired Andeavor, including a controlling interest in ANDX, thus establishing common control between MPLX, ANDX and their respective general partners. Under MPC’s application of the acquisition method of accounting, a portion of the total purchase price was allocated to ANDX’s tangible assets and liabilities and identifiable intangible assets based on their fair values as of October 1, 2018. The excess of the allocated purchase price over those fair values was recorded as goodwill. MPC’s basis in ANDX’s tangible assets, liabilities, identifiable intangible assets and goodwill was transferred to MPLX upon completion of the Merger. As a result of our annual impairment review for goodwill, we determined that a portion of the goodwill that resulted from the Merger was impaired. The remaining goodwill and intangible assets could become impaired in the future and result in additional, material non-cash charges to our future results of operations. The combined partnership’s operating results may be significantly impacted from both the impairment and the underlying trends in the business that triggered the impairment.
If we are unable to make strategic acquisitions on economically acceptable terms from MPC or third parties, our ability to implement our business strategy may be impaired.
In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions. If we are unable to make accretive strategic acquisitions from 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.
Significant acquisitions in the future will involve the integration of new assets or businesses and present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.
Significant future transactions involving the addition of new assets or businesses will present potential risks, which may include, among others:
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inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;
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an inability to successfully integrate, or a delay in the successful integration of, assets or businesses we acquire;
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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;
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a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;
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the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management’s attention from other business concerns;
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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 our Industry
Certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to our unitholders.
Some of our natural gas, crude oil, NGL, and refined product pipelines are, or may in the future be, subject to siting, public necessity or service regulations by FERC or various state or other regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs, crude oil and refined products in interstate commerce and FERC’s regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities (for natural gas pipelines only); rates; operations; accounts and records; and depreciation and amortization policies. FERC’s action in any of these areas or modifications of its current regulations can adversely impact our ability to compete for business, the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of operating our pipelines. FERC also may conduct audits of these facilities, and if FERC determines that we are not in compliance with our tariff or applicable regulations, we may incur additional costs, expenses or penalties. For certain natural gas, NGL, crude oil and refined product common carrier pipelines, we have FERC tariffs on file and we may have additional pipelines in the future that may be subject to these requirements. We also own and are constructing pipelines, including pipelines that carry NGLs between our processing and fractionation facilities, that we believe are either not subject to FERC’s jurisdiction or would otherwise meet the qualifications for a waiver from many or all of FERC’s requirements. However, we cannot provide assurance that FERC will not at some point find that some or all of these pipelines are subject to FERC’s requirements or are otherwise not exempt from certain requirements. Such a finding could subject us to potentially burdensome and expensive operational, reporting and other requirements as well as fines, penalties or other sanctions.
Pipelines and operations not subject to regulation by FERC may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services and that we offer service to our shippers on a not unduly discriminatory basis. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business - Regulatory Matters as set forth in this Annual Report on Form 10-K.
Some of our natural gas, NGL, crude oil and refined product pipelines are subject to FERC’s rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.
A number of our pipelines provide interstate service that is subject to regulation by FERC. FERC prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines. FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in FERC’s approved rate methodologies, or challenges to our application of an approved methodology, could also adversely affect our rates. Additionally, shippers may protest (and FERC may investigate) the lawfulness of tariff rates. FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.
Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.
Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make distributions at our intended levels.
Certain of our senior notes, our revolving credit facility and our loan agreement with MPC Investment LLC (“MPC Investment”) have variable interest rates. As a result, future interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future prior to the applicable stated maturity.
As with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make distributions at our intended levels.
Uncertainty relating to the calculation of LIBOR, and other reference rates and their potential discontinuance may adversely affect interest expense related to our outstanding debt.
National and international regulators and law enforcement agencies have conducted investigations into a number of rates or indices, which are deemed to be “reference rates.” Actions by such regulators and law enforcement agencies may result in changes to the manner in which certain reference rates are determined, their discontinuance, or the establishment of alternative reference rates. In particular, it appears highly likely that LIBOR will be discontinued or modified by the end of 2021.
At this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may, have on LIBOR, other benchmarks or floating rate indebtedness. Uncertainty as to the nature of such potential discontinuance, modification, alternative reference rates or other reforms may materially adversely affect the trading market for securities linked to such benchmarks. Furthermore, the use of alternative reference rates or other reforms could cause the market value of, the applicable interest rate on and the amount of interest paid on our floating rate indebtedness to be materially different than expected and could materially adversely impact our ability to refinance such floating rate indebtedness or raise future indebtedness on a cost effective basis.
Meeting the requirements of evolving environmental or other laws or regulations may result in substantial capital expenditures and operating costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.
Various laws and regulations are expected to impose increasingly stringent and costly requirements on our
operations, which may reduce our cash available for distribution. Laws and regulations expected to become more stringent relate to the following:
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the emission or discharge of materials into the environment,
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solid and hazardous waste management,
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the regulatory classification of materials presently used in our business,
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pollution prevention,
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greenhouse gas emissions,
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climate change,
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public and employee safety and health,
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inherently safer technology, and
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facility security.
The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities and production processes. As a result of these 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. Such expenditures could materially and adversely affect our business, financial condition, results of operations and cash flows.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing could delay or impede producer’s gas production or result in reduced volumes available for our midstream assets to gather, process and fractionate. 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. If federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult to complete natural gas wells in shale formations and increase producers’ costs of compliance.
For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read Item 1. Business - Regulatory Matters and Item 1. Business - Environmental Regulation, each as set forth in this Annual Report on Form 10-K.
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.
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 has announced its intention to withdraw from the Paris Agreement, U.S. climate change strategy and implementation of that strategy through legislation and regulation may change under future
administrations; therefore, the impact to our industry and operations due to greenhouse gas regulation is unknown at this time.
For more information regarding greenhouse gas and methane emission and regulation, please read Item 1. Business - Environmental Regulation - Climate Change.
Severe weather events may adversely affect our facilities and ongoing operations.
We have mature systems in place to manage potential acute physical risks, such as floods, hurricane-force winds, wildfires and snowstorms, and potential chronic physical risks, such as higher ocean levels. If any such events were to occur, they could have an adverse effect on our assets and operations. Specifically, where appropriate, we are hardening and modernizing assets against flood and wind damage and ensuring we have resiliency measures in place, such as storm-specific readiness plans. 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 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.
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:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
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improve data collection, integration and analysis;
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repair and remediate the pipeline as necessary; and
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implement preventive and mitigating actions.
Over the past several years, PHMSA has published new regulations, and issued notices for additional proposed regulations, to expand pipeline safety requirements.
In addition, PHMSA and other state regulators have recently expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities to assess compliance with hazardous liquids pipeline safety requirements, which actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators. The adoption of these and other 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 PHMSA and other state regulators described above, 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.
Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. These regulations have raised operating costs for the industry, and compliance with such laws and regulations may cause us to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities.
The United States inland waterway infrastructure is aging and planned and unplanned maintenance may adversely affect our operations.
Maintenance of the United States 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 United States 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.
Interruptions in operations at any of our facilities or those of our customers, including MPC’s refining operations, may adversely affect our operations and cash flows available for distribution to our unitholders.
Our operations depend upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities, gathering and transportation facilities, an export terminal, various other means of transportation and marketing services. Any significant interruption at these facilities or pipelines, or our customers’ operations, including MPC’s refining operations, or in our ability to gather, transport or store natural gas, NGLs, crude oil or other refined products to or from these facilities or pipelines for any reason, or to market or transport the natural gas, crude oil, NGLs or refined products, would adversely affect our operations and cash flows available for distribution to our unitholders. In some cases, these events may also adversely affect the pricing received for NGLs, and may reduce the volumes of oil, gas, NGLs and refined products that we receive.
Operations at our or our customers’ facilities, including MPC’s refineries, could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:
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unscheduled turnarounds or catastrophic events, including damages to pipelines and facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;
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restrictions imposed by governmental authorities or court proceedings;
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labor difficulties that result in a work stoppage or slowdown;
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a disruption in the supply of natural gas, NGLs, crude oil or refined products to our pipelines, barges, processing and fractionation plants and associated facilities;
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disruption in our supply of power, water and other resources necessary to operate our facilities;
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a marine accident or spill event could close a portion of the inland waterway system;
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damage to our facilities resulting from gas, crude oil, NGLs or refined products that do not comply with applicable specifications; and
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inadequate fractionation, transportation or storage capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGL products.
Our NGL fractionation, storage and marketing operations in the Marcellus and Utica regions are integrated, and as a result, it is possible that an interruption of these operations may impact operations in the other regions, which may exacerbate the impacts of such interruption.
The construction and operation of certain of our facilities in our G&P segment 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.
In addition, our marine transportation business is subject to weather conditions on a daily basis. 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 United States 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, adverse water and weather conditions can negatively affect a towing vessel’s performance, tow size, loading drafts, fleet efficiency, place limitations on night passages and dictate horsepower requirements.
We rely on the performance of our information technology systems, and the interruption or failure of any information technology system, including an interruption or failure due to a cybersecurity breach, could have an adverse effect on our business, financial condition, results of operations and cash flows.
We are heavily dependent on our information technology systems, including our network infrastructure and cloud applications, for the safe and effective operation of our business. We rely on such systems to process, transmit and store electronic information, including financial records and personally identifiable information such as contractor, customer and investor data, and to manage or support a variety of business processes, including our pipeline operations, gathering and processing operations, financial transactions, banking and numerous other processes and transactions. Our systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, malware, power failures, cyber-attacks and other events. We also face various other cybersecurity threats from criminal hackers, state-sponsored intrusion, industrial espionage and contractor malfeasance, including threats to gain unauthorized access to sensitive information or to render data or systems unusable.
Certain vendors have access to sensitive information, including personally identifiable investor and contractor data and a breakdown of their technology systems or infrastructure as a result of a cyber-attack or otherwise could result in unauthorized disclosure of such information.
Our cybersecurity protections, infrastructure protection technologies, disaster recovery plans and employee training may not be sufficient to defend us against all unauthorized attempts to access our information. We have been and may in the future be subject to attempts to gain unauthorized access to our computer network and systems. To date, prior events have not had a material adverse effect on us.
Any cybersecurity incident could result in theft, destruction, loss, misappropriation or release of confidential financial and other data or intellectual property; give rise to remediation or other expense; expose us to liability under federal and state laws; reduce our customers’ willingness to do business with us; disrupt the services we provide to customers; and subject us to litigation and legal liability under federal and state laws. Any of such results could have an adverse effect on our reputation, business, financial condition, results of operations and cash flows available for distribution to our unitholders.
Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.
The U.S. government has issued warnings that energy assets in general, including the nation’s refining, pipeline and terminal infrastructure, may be future targets of terrorist organizations. The threat of terrorist attacks has subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.
Risks Relating to the Business and Operations of MPC
MPC accounted for a large portion of our revenues in 2019 and will continue to do so on a go-forward basis. If MPC changes its business strategy, 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.
For the year ended December 31, 2019, excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that were treated as third-party revenues for accounting purposes, MPC accounted for approximately 56 percent of our operating revenues, including 91 percent of the operating revenues within our L&S segment, and we believe MPC will continue to account for a large portion of our revenues on a go forward basis. As we expect to continue to derive a portion of our revenues from MPC for the foreseeable future, 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:
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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;
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a material decrease in the refining margins at MPC’s refineries;
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disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on which MPC’s business is dependent;
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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;
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MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;
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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;
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state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;
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environmental incidents and violations and related remediation costs, fines and other liabilities;
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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;
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changes in crude oil and refined product inventory levels and carrying costs; and
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disruptions due to hurricanes, tornadoes or other forces of nature.
We have no control over MPC’s business decisions and operations, and MPC may elect to pursue a business strategy that does not favor us and our business. 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 would 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 would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.
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.
MPC is not obligated to use our services with respect to volumes of crude oil or refined products in excess of the minimum volume commitments under the transportation services agreements with us. Our cash available for distribution will be materially and adversely affected to the extent that we do not transport volumes in excess of the minimum volume commitments under our transportation services agreements or if MPC’s obligations under our transportation, terminal, fuels distribution, marketing and storage services agreements are suspended, reduced or terminated. If MPC fails to use our assets and services after expiration of those agreements and we are unable to generate additional revenues from third parties, our ability to make distributions to unitholders may be materially and adversely affected.
In addition, under our transportation services agreements, MPC must pay us a deficiency payment if it fails to transport its minimum throughput commitment. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline in excess of its minimum volume commitment during a specified period under the terms of the applicable transportation services agreement. Upon the expiration or termination of a transportation services agreement, MPC may use any remaining credits against any volumes shipped by MPC on the applicable pipeline for the specified period, as applicable, without regard to any minimum volume commitment that may have been in place during the term of the agreement. If that were to occur, we would not receive any cash payments for volumes shipped on the applicable pipeline until any such remaining credits were fully used or until the expiration of the specified period.
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 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, 2019, MPC had consolidated long-term indebtedness of approximately $28 billion, of which $8 billion was a direct obligation of MPC. 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.
On November 1, 2019, Moody’s announced it had changed its outlook for MPC’s and MPLX’s credit ratings from stable to negative following the recent announcements regarding MPC’s planned spinoff of its Speedway business and its midstream review, and these developments could cause or contribute to a future
determination by one or more of the rating agencies to lower MPLX’s credit ratings. 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.
Risks Relating to Tax Matters
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 the 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. We have requested and received a favorable ruling from the IRS on the treatment of a portion of our “qualifying income.” 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. 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.
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, become taxable income to the unitholder if the common units are sold at a price greater than the unitholder’s tax basis in those common units, even if the price the unitholder receives is less than the unitholder’s original cost. 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 a tax liability in excess of the amount of cash received from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons 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. 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. Furthermore, non-U.S. persons may be subject to tax on the gain on sale of their common units to the extent the gain is attributable to effectively connected income. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.
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.
To maintain 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 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 approximately 35 states. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or conduct
business in additional states that impose a personal income tax. 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 loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he 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 who loans his common units to a “short seller” to cover a short sale of common units (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 to the short seller, 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 loan to a short seller are urged 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.
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 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 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. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use 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.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it 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.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability 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. 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.
Risks Relating to Ownership of our Common Units
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.
MPC owns our general partner and approximately 63 percent of our outstanding common units as of February 17, 2020. 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 these decisions in the best interests of the stockholders of MPC;
•
MPC, as a significant customer, has an economic incentive to cause us to not seek higher tariff rates, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;
•
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. 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.
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 17, 2020, our general partner and its affiliates owned approximately 63 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 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 17, 2020, MPC held 665,997,540 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.
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.
Item 1B.
Item 1B. Unresolved Staff Comments
None
Item 2.
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, 2019.
(1)
Includes approximately 21 miles of crude pipeline and approximately 158 miles of refined product pipeline leased from third parties.
(2)
Includes approximately 1,921 miles of crude pipeline in which we have a 9.2 percent ownership interest, 168 miles of crude pipeline in which we have a 35.0 percent ownership interest, 48 miles of crude pipeline in which we have a 40.7 percent ownership interest, 57 miles of crude pipeline in which we have a 58.5 percent ownership interest, 118 miles of crude pipeline in which we have a 67.0 percent ownership interest and 975 miles of crude pipeline in which we have a 17.0 percent ownership interest. Also includes approximately 1,830 miles of refined product pipeline in which we have a 24.5 percent ownership interest and 87 miles of refined product pipeline in which we have a 65.16 percent ownership interest.
(3)
Includes approximately 399 miles of inactive crude pipeline and 232 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 on the Ozark pipeline; Western Canada, Wyoming and North Dakota on the Keystone, Platte, Mustang and Enbridge pipelines; and the Gulf Coast on the Capline crude oil pipeline. 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 marketing 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 marketing terminals, which support MPC’s integrated midstream business.
Terminal Assets
The following table sets forth certain information regarding our owned and operated terminals as of December 31, 2019.
(1)
MPLX also operates one leased terminal and has partial ownership interest in one terminal, with a combined tank shell capacity of 1,045 mbbls.
(2)
This terminal is accounted for as an equity method investment.
Marine Assets
The following table sets forth certain information regarding our marine assets as of December 31, 2019. The marine business currently has an associated transportation service agreement with MPC.
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 an 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, rail and truck racks, and docks owned by us, serving MPC’s refineries as of December 31, 2019. Each of the following assets are currently included in storage services agreements with MPC.
Other L&S Assets
The following tables set forth certain information regarding our other midstream assets as of December 31, 2019, each of which currently have an associated transportation services agreement or storage services agreement with MPC.
(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 40.7 percent interest in LOOP, which includes a deep-water oil port and crude oil storage.
(3)
The Mt. Airy Terminal includes 37 tanks, 2-bay ethanol loading rack, 3-vessel barge/ship dock and 7 dock loading lines.
(4)
We own and operate 28 tank farms and operate two leased tank farms.
(5)
All capacities reflect 100 percent of the pipeline systems’ capacity in thousands of barrels per day.
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, 2019. All throughputs and utilizations included are weighted-averages for days in operation. See further discussion about our joint ventures in Item 8. Financial Statements and Supplementary Data - Note 5.
Gas Processing Complexes
(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 272 MMcf/d, that exceeded our 40 percent share of the capacity of 220 MMcf/d, are not included in this table as we own a non-operating interest.
Fractionation & Condensate Stabilization Facilities
(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 938 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 Shale, Utica Shale, and Appalachia region under an agreement with a third party. Lastly, we have up to 240 thousand barrels of propane storage with third parties 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, 2019, the Marcellus Operations and Utica Operations utilized an average of 83
percent and 17 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 Hopedale 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. We also have large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading a 20 thousand barrel barge.
De-ethanization Facilities
(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.
Natural Gas Gathering Systems
(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, 2019 were 127 MMcf/d.
NGL Pipelines
(1)
Includes 38 miles of inactive pipeline.
Title to Properties
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. We believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. In addition, our L&S segment leases vehicles, building spaces, and pipeline equipment under long-term operating leases, most of which include renewal options. Our L&S segment also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020. 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, but 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 all of 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 22, 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 by our Predecessor or us, 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.
Item 3. Legal Proceedings
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.
Litigation
MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio Fractionation and MarkWest Utica EMG (collectively, the “MPLX Parties”) were parties to various lawsuits with Bilfinger Westcon, Inc. (“Westcon”) that were instituted in 2016 and 2017 in the Court of Common Pleas in Butler County, Pennsylvania, the Circuit Court in Wetzel County, West Virginia, and the Court of Common Pleas in Harrison County, Ohio. The lawsuits related to disputes regarding construction work performed by Westcon at the Bluestone, Mobley and Cadiz processing complexes in Pennsylvania, West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. As previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, in July 2019, Westcon and the MPLX Parties reached an agreement to resolve the disputes among those parties relating to the Bluestone processing complex in Pennsylvania. In the quarter ended December 31, 2019, Westcon and the MPLX Parties reached agreements to resolve the remaining disputes among those parties relating to the Mobley
and Cadiz processing complexes in West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. The settlements will not have a material adverse effect on MPLX’s consolidated financial position, results of operations or cash flows.
Item 4.
Item 4. Mine Safety Disclosure
Not applicable
Part II
Item 5.
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common limited partner units are listed on the NYSE and traded under the symbol “MPLX”. As of February 17, 2020, there were 267 registered holders of 392,418,325 outstanding common units held by the public, including 392,045,653 common units held in street name. In addition, as of February 17, 2020, MPC and its affiliates owned 665,997,540 of our common units, constituting approximately 63 percent of the outstanding common units. In addition, MPC, through our general partner, owns a non-economic general partnership interest in us.
Distributions of Available Cash
Our Partnership Agreement requires that, within 60 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.
Definition of available cash. Available cash is defined in our Partnership Agreement. Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:
•
less the amount of cash reserves established by our general partner to:
•
provide for the proper conduct of our business (including reserves for our future capital expenditures and for anticipated future credit needs);
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comply with applicable law, any of our debt instruments or other agreements or obligations; or
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provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units for the current quarter);
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plus, if our general partner so determines, all or any portion of the cash on hand resulting from working capital borrowings made subsequent to the end of such quarter.
Intent to Distribute the Minimum Quarterly Distribution. Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units of $0.2625 per unit, or $1.05 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our Partnership Agreement. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Debt and Liquidity Overview, for a discussion of the restrictions included in our bank revolving credit facility that may restrict our ability to make distributions.
Preferred Unit Distributions
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. Series B preferred unitholders are entitled to receive a fixed distribution of $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. MPLX may not pay any distributions for any quarter on any junior securities, including any of the common units, unless the distribution payable to the preferred units with respect to such quarter, together with any previously accrued and unpaid distributions to the preferred units, have been paid in full.
Recent Sales of Unregistered Units
In connection with the closing 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.
Additionally, as a result of the Merger, each ANDX TexNew Mex Unit issued and outstanding immediately prior to the effective time of the Merger was converted into a right for Western Refining Southwest, Inc. (“Southwest, Inc.”), a wholly-owned subsidiary of MPC, as the holder of all such units, to receive a unit representing a substantially equivalent special limited partner interest in MPLX (the “MPLX TexNew Mex Units”). By virtue of the conversion, all ANDX TexNew Mex Units were cancelled and ceased to exist as of the effective time of the Merger. The MPLX TexNew Mex Units are a new class of units in MPLX substantially equivalent to the ANDX TexNew Mex Units, including substantially equivalent rights, powers, duties and obligations that the ANDX TexNew Mex Units had immediately prior to the closing of the Merger. 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 Southwest, Inc., 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.
The issuance of MPLX TexNew Mex Units and the MPLX Special Limited Partner Interest was effected in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
Item 6.
Item 6. Selected Financial Data
The following table shows selected historical consolidated financial data of MPLX LP as of the dates and for the years indicated. The following table also presents the non-GAAP financial measures of Adjusted EBITDA and DCF, which we use in our business. For the definitions of Adjusted EBITDA and DCF and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, see Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
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, Item 6. Selected Financial Data 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 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. Our L&S segment primarily engages in the transportation, storage, distribution and marketing of crude oil, asphalt and refined petroleum products. The L&S segment also includes the operation of our inland marine business, terminals, rail facilities, storage caverns and refining logistics. Our G&P segment primarily engages in the gathering, processing and transportation of natural gas as well as the gathering, transportation, fractionation, storage and marketing of NGLs. The assets and operations of our L&S and G&P segments described above include the assets and operations of Andeavor Logistics LP (“ANDX”) acquired via merger on July 30, 2019, which complemented our existing business in addition to expanding our operations to the West Coast.
RECENT DEVELOPMENTS
On February 21, 2020, MPLX, through a wholly-owned subsidiary, formed a joint venture with Delek US Energy, Inc. ("Delek") (the "WWP Project Financing JV") for the specific purpose of financing a portion of MPLX’s and Delek’s combined construction costs for the Wink to Webster pipeline system. Both MPLX and Delek contributed their respective 15 percent ownership interests in the Wink to Webster Pipeline JV to the WWP Project Financing JV. Also on February 21, 2020, the WWP Project Financing JV, through a wholly-owned subsidiary, entered into a committed term loan facility with a syndicate of lenders providing for up to approximately $608 million in term loan borrowings to, among other things, fund future capital calls received from the Wink to Webster Pipeline JV and pay debt service costs under the term loan facility prior to the commercial operation date of the Wink to Webster pipeline system. The WWP Project Financing JV pledged the combined 30 percent interest in the Wink to Webster Pipeline JV contributed to it by MPLX and Delek to secure its obligations under the term loan facility.
On January 23, 2020, we announced the board of directors of our general partner had declared a distribution of $0.6875 per common unit that was paid on February 14, 2020 to common unitholders of record on February 4, 2020.
MPC’s board of directors has formed a special committee to evaluate strategies to enhance shareholder value through a review of its Midstream business and to analyze, among other things, the strategic fit of
assets with MPC, the ability to realize full valuation credit for midstream earnings and cash flow, balance sheet impacts including liquidity and credit ratings, transaction tax impacts, separation costs, and overall complexity.
SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
During 2019, we were able to focus and execute on our strategic vision by growing our business across the midstream value chain and investing in new or existing assets to enhance the stability of our cash flows, while at the same maintaining our investment grade credit profile. Significant financial and other highlights for the year ended December 31, 2019 are shown in the chart below. Refer to the Results of Operations and the Liquidity and Capital Resources sections for further details.
(1) Includes goodwill impairment of $1.2 billion within our G&P operating segment.
(2) Includes Adjusted EBITDA attributable to Predecessor and DCF adjustments attributable to Predecessor.
Additional highlights for the year ended December 31, 2019 include:
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MPLX completed the acquisition of ANDX via Merger on July 30, 2019. The historical results of ANDX have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired Andeavor. At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The assets of ANDX complement and enhance MPLX’s existing asset base and further expand MPLX’s existing footprint.
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MPLX entered into a joint venture agreement related to the Wink-to-Webster crude oil pipeline, which remains on schedule to be completed in the first half of 2021 and has 100 percent of the contractible capacity committed with minimum volume commitments. This is a 36-inch diameter pipeline with a capacity of 1.5 million barrels per day which will originate in the Permian Basin and have destination points in the Houston market, including MPC’s Galveston Bay refinery.
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We also entered into a joint venture agreement related to the design and construction of the Whistler Pipeline. The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport approximately 2 Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The majority of available capacity on the planned pipeline has been committed with minimum volume commitments. The pipeline is expected to be in service in the second half of 2021.
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Additionally, we continue to execute on our organic growth plan through terminal and marine fleet expansions, the expansion of processing and fractionating capacity at numerous plants, as well as having a continued focus on the optimization of our portfolio of assets, which could include asset divestitures.
Financing Activities
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During the year, MPLX: entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement to $3.5 billion; extended the maturity of the MPLX Credit Agreement to July 30, 2024; and paid off $500 million aggregate principal amount of the outstanding ANDX 5.5 percent senior notes due 2019 at maturity.
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In connection with the Merger, MPLX also assumed all outstanding ANDX senior notes, which had an aggregate principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion new senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX, of which $500 million aggregate principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid off on October 15, 2019 at maturity as described above.
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During the year ended December 31, 2019, we did not issue any common units under our ATM Program. As of December 31, 2019, $1.7 billion of common units remain available for issuance through the ATM Program.
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 and DCF. 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) net interest and other financial costs; (iii) net maintenance capital expenditures; (iv) equity method investment capital expenditures paid out; and (v) other non-cash items. 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 believe that the presentation of Adjusted EBITDA and DCF 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. Adjusted EBITDA and DCF should not be considered alternatives to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and DCF 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. Adjusted EBITDA and DCF should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and DCF may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and DCF 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.
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).
RESULTS OF OPERATIONS
The following table and discussion is a summary of our results of operations for the years ended 2019, 2018 and 2017, 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. Prior period financial information has been retrospectively adjusted for common control transactions.
(1)
Includes impairment expense of $42 million related to two equity method investments in 2019.
(2)
Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Excludes adjusted EBITDA and DCF adjustments attributable to Predecessor.
(3)
Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Includes adjusted EBITDA and DCF adjustments attributable to Predecessor.
(1)
Includes impairment expense of $42 million related to two equity method investments in 2019.
(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 MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B preferred (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 unitholders.
(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 MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B preferred (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 unitholders.
2019 Compared to 2018
Service revenue increased $642 million in 2019 compared to 2018, of which $490 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. Additionally, higher fees from higher volumes in the Marcellus, Southwest and Bakken regions, partially offset by lower cost reimbursement revenue in the Marcellus region resulted in a net increase of $130 million. The remainder of the variance is related to a slight increase in volume and transportation rates of crude and refined products shipped.
Service revenue-related parties increased $1,051 million in 2019 compared to 2018, of which $731 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to an additional $74 million of revenue from the acquisition of MPLX Refining Logistics LLC (“Refining Logistics”) and MPLX Fuels Distribution LLC (“Fuels Distribution”) on February 1, 2018, as well as from annual fee escalations; $98 million from increased volume and transportation rates of crude and refined product shipped; a $24 million increase from additional marine vessels; $8 million from storage services revenue due to increased capacity; $16 million from increased terminal throughput; and $2 million from the recognition of revenue related to volume deficiencies. The remaining variance is due to reclassifications of certain lease revenue between rental income and service revenue as well as to other miscellaneous items.
Rental income increased $36 million in 2019 compared to 2018, of which $13 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to an increase from the acquisition of the Mt. Airy Terminal as well as increased volumes in the Marcellus region.
Rental income-related parties increased $350 million in 2019 compared to 2018, of which $389 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. Also contributing to the variance was an additional $46 million of revenue from the acquisition of Refining Logistics; an additional $6 million from the completion of a new butane cavern; a $3 million increase in terminal throughput; and an additional $5 million from the acquisition of the Mt. Airy Terminal. These increases were offset by a $96 million decrease due to reclassification of certain lease revenue between rental income and service revenue.
Service revenue-product related, product sales and product sales-related parties decreased $106 million in 2019 compared to 2018, primarily due to lower prices in the Southwest, Southern Appalachia and Marcellus region of $422 million offset by volume increases in the Southwest of $162 million. A portion of the volume increase in the Southwest was offset by a volume decrease due to downtime at the Javelina facility. The overall decrease was also offset by an increase of $137 million due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018 and by an increase of $22 million due to stronger margins in the wholesale fuels business. The remainder of the variance is due to a decrease from commodity contracts in 2018.
Income (loss) from equity method investments increased $43 million in 2019 compared to 2018, of which $30 million was due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to increases in our MarEn Bakken Company, LLC, Sherwood Midstream, MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Lincoln Pipeline LLC, and Utica EMG joint ventures, partially offset by decreases in our Explorer Pipeline Co., Three Rivers Gathering LLC, Ohio Condensate Company, LLC, and LOCAP L.L.C. joint ventures. This includes impairment charges recognized related to our Ohio Condensate Company, L.L.C. and Three Rivers Gathering LLC joint ventures of $42 million.
Other income and Other income-related parties increased $20 million in 2019 compared to 2018. This variance was primarily due to an increase in management fees from our joint ventures and net gains on sales of assets during the year.
Cost of revenues increased $393 million in 2019 compared to 2018. This variance was primarily due to an increase of $400 million due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to increased costs to operate new and
expanded assets such as the Mt. Airy Terminal, the expanded Ozark pipeline, additional marine vessels, and the completed Robinson Butane cavern. There was also increased spend on projects, as well as other miscellaneous items. These increases were partially offset by decreases in reimbursable costs as well as certain employee-related costs.
Purchased product costs decreased $138 million in 2019 compared to 2018. This was primarily due to lower prices of $280 million in the Southwest and Southern Appalachia as well as a decrease in unrealized derivative gains from prior year. These decreases were partially offset by higher volumes of $119 million in the Southwest and Southern Appalachia and an increase of $20 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018.
Rental cost of sales increased $6 million in 2019 compared to 2018 primarily due to the acquisition of the Mt. Airy Terminal.
Rental cost of sales-related parties increased $134 million in 2019 compared to 2018, of which $116 million was due to the Merger. The remainder of the variance relates to the acquisition of the Mt. Airy Terminal and other miscellaneous items.
Purchases-related parties increased $306 million in 2019 compared to 2018, of which $204 million was due to the Merger. The remaining variance was primarily due the acquisition of Refining Logistics and Fuels Distribution as well as to increases in certain employee-related costs.
Depreciation and amortization expense increased $387 million in 2019 compared to 2018, of which $277 million was due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The acquisitions of Refining Logistics and the Mt. Airy Terminal resulted in an increase of approximately $25 million with the remainder of the variance being related to additions to in-service property, plant and equipment throughout the year.
Impairment expense increased $1,197 million in 2019 compared to 2018. This variance is due to the fourth quarter of 2019 goodwill impairment.
General and administrative expenses increased $72 million in 2019 compared to 2018. This variance was primarily due to an increase of $65 million due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018; this includes $14 million of acquisition costs related to the Merger. The remaining variance is due to the acquisition of Refining Logistics and Fuels Distribution and other employee-related costs.
Other taxes increased $30 million in 2019 compared to 2018. This variance was primarily due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018.
Interest expense and other financial costs (including related parties) increased $201 million in 2019 compared to 2018. The increase is primarily due to increased interest and financing costs related to the senior notes issued in the fourth quarter of 2018, interest on the new variable rate notes and term loan issued in the third quarter of 2019 and inclusion of the ANDX senior notes during the full year 2019 but only for the last three months of 2018.
2018 Compared to 2017
Service revenue increased $700 million in 2018 compared to 2017, of which $152 million was attributable to the Merger. The remaining variance was primarily due to a $167 million increase in fees from volume growth in the Marcellus and the Southwest regions; a $13 million increase related to increases in volume and transportation rates of crude oil and refined products shipped, partially attributable to the Ozark pipeline acquisition and expansion; and an increase of $369 million due to ASC 606 gross ups. The remainder of the change can be attributable to impacts related to ASC 606 classification changes and other miscellaneous items.
Service revenue-related parties increased $1,322 million in 2018 compared to 2017, of which $245 million was attributable to the Merger. The remaining variance was primarily due to a $947 million increase from the acquisition of Refining Logistics and Fuels Distribution; a $100 million increase related to higher
volumes and transportation rates of related-party crude oil and refined products shipped, partially attributable to the Ozark pipeline acquisition and expansion; a $15 million increase from additional boats and barges; a $10 million increase from higher terminal throughputs; and a $12 million increase in the recognition of revenue related to volume deficiencies. These increases were partially offset by ASC 606 classification changes of $7 million.
Service revenue-product related increased $220 million in 2018 compared to 2017, of which $22 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 classification and non-cash changes.
Rental income increased $75 million in 2018 compared to 2017, of which $3 million was attributable to the Merger. The remaining variance was primarily due to a $6 million increase from the acquisition of the Mt. Airy Terminal as well as $65 million related to higher ASC 606 cost reimbursements.
Rental income-related parties increased $567 million in 2018 compared to 2017, of which $128 million was attributable to the Merger. The remaining variance was primarily due to a $411 million increase from the acquisition of Refining Logistics with the remainder of the variance being primarily related to the acquisition of additional marine vessels and the completion of the Robinson Butane Cavern.
Product sales and product sales-related parties increased $77 million in 2018 compared to 2017, of which $23 million was attributable to the Merger. The remaining variance was primarily due to higher prices in the Southwest, Northeast and Marcellus regions of $113 million, volume impacts of $9 million as well as a change in unrealized gains associated with derivatives of $10 million, driven by favorable product hedges in 2018 compared to unfavorable product hedges in 2017. These increases were partially offset by ASC 606 classification and non-cash changes of $78 million.
Income (loss) from equity method investments increased $169 million in 2018 compared to 2017, of which $7 million was attributable to the Merger. The remaining variance was primarily due to the MarEn Bakken acquisition, the Joint-Interest Acquisition, growth in the Jefferson Dry Gas joint venture as a result of an increase in dry gas gathering volumes, as well as growth in the Sherwood Midstream joint venture due to additional plants coming online. This was partially offset by a decrease in our Utica EMG joint venture as a result of decreased volumes and the buy-out of an equity method investment partner.
Other income and Other income-related parties increased $8 million in 2018 compared to 2017. This variance was primarily due to an increase in management fees from our joint ventures.
Cost of revenues increased $568 million in 2018 compared to 2017, of which $148 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 gross-ups of $369 million, higher repairs and maintenance and operating costs in the Marcellus and Southwest regions of $32 million as well as from the acquisition of Refining Logistics and the acquisition and expansion of the Ozark pipeline.
Purchased product costs increased $173 million in 2018 compared to 2017, of which a $21 million decrease was attributable to the Merger. The remaining variance was primarily due to higher NGL and gas prices and volumes of approximately $68 million and $36 million, respectively, primarily in the Southwest and Northeast areas; and an increase due to ASC 606 imbalances and non-cash consideration of approximately $105 million with the remaining variance being related to derivative activity.
Rental cost of sales and rental cost of sales-related parties increased $102 million in 2018 compared to 2017, of which $26 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 gross ups of $65 million in addition to the acquisition of Mt. Airy Terminal and increased maintenance, repairs, and operating costs.
Purchases-related parties increased $470 million in 2018 compared to 2017, of which $65 million was attributable to the Merger. The remaining variance was primarily due to $372 million from the acquisition of Refining Logistics and Fuels Distribution with the remainder of the variance primarily being related to increases in employee-related costs.
Depreciation and amortization expense increased $184 million in 2018 compared to 2017, of which $101 million was attributable to the Merger. The remaining variance was primarily due to the acquisitions of Refining Logistics and the Mt. Airy Terminal for approximately $76 million, as well as additions to in-service property, plant and equipment, slightly offset by accelerated depreciation expense incurred in 2017 related to decommissioned assets.
General and administrative expenses increased $75 million in 2018 compared to 2017, of which $25 million was attributable to the Merger. The remaining variance was primarily due to the acquisition of Refining Logistics and Fuels Distribution as well as increased labor and benefits costs.
Other taxes increased $29 million in 2018 compared to 2017, of which $11 million was attributable to the Merger. The remaining variance was primarily due to the acquisition of Refining Logistics as well as the Ozark pipeline acquisition and expansion.
Interest expense and other financial costs increased $360 million in 2018 compared to 2017, of which $53 million was attributable to the Merger. The remaining variance was primarily due to increased interest expense due to the new senior notes issued in February 2018 and November 2018 and the loss on debt extinguishment associated with the redemption of all of the outstanding 5.5 percent senior notes due February 2023.
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, 2019, 2018 and 2017.
L&S Segment
L&S Segment Financial Highlights (in millions)
(1)
Includes results of Predecessor.
(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.
2019 Compared to 2018
Service revenue increased $1,190 million in 2019 compared to 2018, of which $848 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. Other impacts include an additional $74 million of revenue from the acquisition of Refining Logistics and Fuels Distribution on February 1, 2018, as well as from annual fee escalations; $122 million from increased volume and transportation rates of crude and refined product shipped; $24 million from additional marine vessels; $8 million from storage services revenue due to increased capacity; $16 million from increased terminal throughput; and $2 million from the recognition of revenue related to volume deficiencies. The remaining variance is due to a $89 million increase due to reclassification of certain lease revenue between rental income and service revenue as well as to other miscellaneous items.
Rental income increased $379 million in 2019 compared to 2018, of which $402 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to an additional $46 million of revenue from the acquisition of Refining Logistics on February 1, 2018; an additional $6 million from the completion of a new butane cavern; a $3 million increase in terminal throughput; and an additional $21 million from the acquisition of the Mt. Airy Terminal. These increases were offset by a $96 million decrease due to reclassification of certain lease revenue between rental income and service revenue and other miscellaneous items.
Product related revenue increased $68 million in 2019 compared to 2018, of which $46 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is primarily due to stronger margins in the wholesale fuels business.
Income from equity method investments increased $29 million in 2019 compared to 2018, of which $19 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was due to increases in our MarEn Bakken Company, LLC and Lincoln Pipeline LLC joint ventures due to increased throughput volumes partially offset by decreases in our Explorer Pipeline Co. joint venture due to an upward adjustment to income in 2018 for a change in the corporate tax rate and our LOCAP LLC joint venture due to lower throughput volumes.
Other Income increased $14 million in 2019 compared to 2018, primarily related to a gain recognized on the sale of assets and other miscellaneous items.
Cost of revenues increased $430 million in 2019 compared to 2018, of which $396 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to increased costs to operate new and expanded assets such as the Mt. Airy Terminal, the expanded Ozark pipeline, additional marine vessels, and the completed Robinson Butane cavern. There was also increased spend on projects, as well as other miscellaneous items. These increases were partially offset by a decrease due to certain employee-related costs.
Purchases - related parties increased $174 million in 2019 compared to 2018, of which $83 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to the acquisition of Refining Logistics and Fuels Distribution and increased employee-related costs.
Depreciation and amortization increased $195 million in 2019 compared to 2018, of which $162 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance was primarily due to the acquisitions of Refining Logistics and the Mt. Airy Terminal as well as additions to in-service property, plant and equipment throughout the year.
General and administrative expenses increased $37 million in 2019 compared to 2018, of which $34 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. There was also an increase due to acquisition costs incurred during 2019, which were offset by lower employee related costs in the fourth quarter of 2019 when compared to the fourth quarter of 2018 as it relates to ANDX.
Other taxes increased $16 million in 2019 compared to 2018 due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018.
2018 Compared to 2017
Service revenue increased $1,375 million in 2018 compared to 2017, of which $286 million was attributable to the Merger. The remaining variance was primarily due to an additional $947 million of revenue from the acquisition of Refining Logistics and Fuels Distribution; a $113 million increase in volume and transportation rates of crude and refined product shipped, partially attributable to the Ozark pipeline acquisition and expansion; a $15 million increase from additional marine vessels; an additional $10 million from increased terminal throughput; and a $12 million increase in the recognition of revenue
related to volume deficiencies. These increases were partially offset by ASC 606 classification changes and other miscellaneous items.
Rental income increased $577 million in 2018 compared to 2017, of which $131 million was attributable to the Merger. The remaining variance was primarily due to an additional $411 million of revenue from the acquisition of Refining Logistics and Fuels Distribution, an additional $16 million from the completion of a new butane cavern, a $14 million increase from additional marine vessels, and an additional $6 million from the acquisition of the Mt. Airy Terminal.
Product related revenue increased $23 million in 2018 compared to 2017, of which $9 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 classification changes.
Income from equity method investments increased $135 million in 2018 compared to 2017, of which $5 million was attributable to the Merger. The remaining variance was primarily due to the Joint-Interest Acquisition and the acquisition of MarEn Bakken.
Cost of revenues increased $166 million in 2018 compared to 2017, of which $135 million was attributable to the Merger. The remaining variance was primarily due to an additional $13 million from the acquisition of Refining Logistics and Fuels Distribution, $7 million from the acquisition of Ozark pipeline and related expansion, $4 million from the acquisition of the Mt. Airy Terminal and $7 million for other miscellaneous items.
Purchases - related parties increased $399 million in 2018 compared to 2017, of which $13 million was attributable to the Merger. The remaining variance was primarily due to a $372 million increase from the acquisition of Refining Logistics and Fuels Distribution as well as an increase in employee-related costs.
Depreciation and amortization increased $145 million in 2018 compared to 2017, of which $68 million was attributable to the Merger. The remaining variance was primarily due to the acquisitions of Refining Logistics, Fuels Distribution and the Mt. Airy Terminal.
General and administrative expenses increased $55 million in 2018 compared to 2017, of which $19 million was attributable to the Merger. The remaining variance was primarily due to an additional $22 million from the acquisition of Refining Logistics and Fuels Distribution as well as increased other miscellaneous expenses.
Other taxes increased $23 million in 2018 compared to 2017, of which $9 million was attributable to the Merger. The remaining variance was primarily due to the acquisition of Refining Logistics and Fuels Distribution as well as the Ozark pipeline acquisition and expansion.
G&P Segment
G&P Segment Financial Highlights (in millions)
(1)
Includes results of Predecessor.
(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)
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.
2019 Compared to 2018
Service revenue increased $503 million in 2019 compared to 2018, of which $375 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is a result of higher fees from higher volumes of $189 million in the Marcellus, Southwest and Bakken regions partially offset by lower cost reimbursement revenue in the Marcellus region of $59 million and other miscellaneous decreases.
Rental income increased $7 million in 2019 compared to 2018. This variance was primarily due to increased volumes in the Marcellus region.
Product related revenue decreased $174 million in 2019 compared to 2018 due to lower prices in the Southwest, Southern Appalachia, Marcellus, Bakken and Rockies regions of $422 million offset by volume increases in the Southwest, Bakken and Rockies of $162 million. A portion of the volume increase in the Southwest was offset by a volume decrease due to downtime at the Javelina facility. The overall decrease was also offset by an increase of $91 million due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remainder of the variance is due to a decrease from commodity contracts in 2018.
Income from equity method investments increased $14 million in 2019 compared to 2018, of which $11 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. There was also an increase of $49 million related to three of our joint ventures. The Sherwood Midstream joint venture increased due to additional plants coming online at the end of 2018 while the Jefferson Dry Gas joint venture increased as a result of higher dry gas gathering volumes and assets placed in service and the Utica EMG joint venture increased as a result of assets written off in the prior period. These increases were partially offset by a decrease in our Ohio Condensate Company, LLC and Three Rivers Gathering LLC joint ventures, which had impairments of approximately $42 million in 2019. Additionally, Delaware Basin Residue, LLC joint venture decreased due to unrealized derivative losses.
Other income increased $6 million in 2019 compared to 2018. This variance was primarily due to an increase in management fees from our joint ventures and net gains on sales of assets during the year.
Cost of revenues increased $103 million in 2019 compared to 2018, of which $122 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. Additionally, we experienced higher repairs and maintenance costs in the Southwest and Marcellus regions of $37 million which were offset by lower reimbursable costs of $59 million in the same regions.
Purchased product costs decreased $138 million in 2019 compared to 2018. This was primarily due to lower prices of $280 million in the Southwest and Southern Appalachia. These decreases were partially offset by higher volumes of $119 million in the Southwest and Southern Appalachia and an increase of $20 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018, as well as a decrease in unrealized derivative gains from prior year.
Purchases - related parties increased $132 million in 2019 compared to 2018, of which $121 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is attributable to an increases in employee-related costs.
Depreciation and amortization increased $192 million in 2019 compared to 2018, of which $115 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is attributable to additions to in-service property, plant and equipment throughout 2018 and 2019 and accelerated depreciation recorded in 2019, which was slightly offset by write-downs of equipment no longer in use in the prior year.
Impairment expense increased $1,197 million as a result of our 2019 annual impairment test over goodwill. The impairment was primarily driven by the slowing of drilling activity, which has reduced production growth forecasts from our producer customers.
General and administrative expenses increased $35 million in 2019 compared to 2018, of which $20 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remainder of the variance is attributable to higher employee related costs.
Other taxes increased $14 million in 2019 compared to 2018, of which $9 million is due to ANDX being included in 2019 results for the full year, but only for the last three months of 2018. The remaining variance is attributable to higher property taxes.
2018 Compared to 2017
Service revenue increased $647 million in 2018 compared to 2017, of which $111 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 cost reimbursements of $369 million and higher fees from higher volumes in the Marcellus and Southwest regions of $167 million.
Rental income increased $65 million in 2018 compared to 2017. This variance was primarily due to higher ASC 606 cost reimbursements of $65 million.
Product related revenue increased $274 million in 2018 compared to 2017, of which $36 million was attributable to the Merger. The remaining variance was primarily due to higher prices in the Southwest, Northeast and Marcellus regions of $113 million, volume impacts of $9 million as well as ASC 606 classification and non-cash changes of $106 million. In addition, there was a change in unrealized gains associated with derivatives of $10 million, driven by favorable product hedges in 2018 compared to unfavorable product hedges in 2017.
Income from equity method investments increased $34 million in 2018 compared to 2017, of which $2 million was attributable to the Merger. The remaining variance was primarily due to growth in the Jefferson Dry Gas joint venture as a result of an increase in dry gas gathering volumes as well as growth in the Sherwood Midstream joint venture due to additional plants coming online. This was partially offset by a decrease in our Utica EMG joint venture as a result of decreased volumes and the buy-out of an equity method investment partner.
Other income increased $8 million in 2018 compared to 2017. This variance was primarily due to an increase in management fees from our joint ventures.
Cost of revenues increased $504 million in 2018 compared to 2017, of which $39 million was attributable to the Merger. The remaining variance was primarily due to ASC 606 gross ups of $433 million as well as higher repairs and maintenance and operating costs in the Marcellus and Southwest regions of $32 million.
Purchased product costs increased $173 million in 2018 compared to 2017. This variance was primarily due to higher prices of $68 million and volumes of $36 million in the Southwest and Northeast as well as ASC 606 imbalances and non-cash consideration of $105 million. These increases were partially offset by a $21 million decrease due to the Merger and unrealized gains and losses associated with derivatives of $15 million, which was driven by NGL prices creating a smaller fractionation spread.
Purchases - related parties increased $71 million in 2018 compared to 2017, of which $52 million was attributable to the Merger. The remaining variance was primarily due to employee-related costs.
Depreciation and amortization increased $39 million in 2018 compared to 2017, of which $33 million was attributable to the Merger. The remaining variance primarily relates to accelerated depreciation taken in 2017 of approximately $33 million offset by additions to in-service property, plant and equipment throughout 2017 and 2018 as well as a write-down of construction in progress projects of approximately $10 million, which are no longer expected to be completed.
General and administrative expenses increased $20 million in 2018 compared to 2017, of which $6 million was attributable to the Merger. The remaining variance was primarily due to increases in labor and benefits costs and general increases in office expense.
Other taxes increased $6 million in 2018 compared to 2017, of which $2 million was attributable to the Merger. The remaining variance was primarily due to an increase in property taxes.
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash, cash equivalents and restricted cash balance was $15 million at December 31, 2019, compared to $85 million at December 31, 2018. The change in cash and cash equivalents was due to the factors discussed below. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years were as follows:
Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $1,011 million in 2019 compared to 2018. This change is a result of a decrease in net income of $544 million offset by a goodwill impairment recognized in the amount of approximately $1.2 billion. Changes related to depreciation and amortization, equity method investments and working capital items also had an impact on the overall change from prior year, most of which were directly impacted by the Merger.
Net cash provided by operating activities increased $1,164 million in 2018 compared to 2017, of which $245 million is due to the Merger. The majority of the remaining $919 million increase is related to the increase in net income net of non-cash adjustments of approximately $931 million period over period. 2018 includes Refining Logistics and Fuels Distribution as of February 1, 2018 as well as Joint-Interest Acquisition assets as of September 1, 2017.
Cash Flows Used in Investing Activities. Net cash used in investing activities increased $185 million in 2019 compared to 2018 primarily due to spending related to the capital budget as well as increased investments in equity method investments, offset by a decrease in cash used for acquisitions due to the Mt. Airy Terminal acquisition in 2018.
Net cash used in investing activities increased $570 million in 2018 compared to 2017, of which $192 million is due to the Merger. The majority of the remaining $378 million increase was primarily due to the Mt. Airy Terminal acquisition as well as various capital projects that have taken place throughout 2018 in-line with MPLX’s capital growth plan. The impact of this activity in 2018 was partially offset by the Ozark pipeline acquisition and higher investments in unconsolidated affiliates which occurred in 2017.
Cash Flows Used in and Provided by Financing Activities. The change in financing activities was a $1,089 million use of cash in 2019 compared to a $117 million use of cash in 2018. The uses of cash in 2019 primarily consisted of $8,719 million of repayments of borrowings under loan agreements with MPC, the $500 million redemption of the 5.5 percent senior notes due October 2019, $7,424 million of repayments under the MPLX and ANDX Credit Agreements and including payments on financing leases, debt issuance costs of $20 million, distributions of $102 million and $30 million to preferred unitholders and noncontrolling interests respectively, distributions of $2,435 million to unitholders related to the increase in units outstanding as well as an increase in the distribution per limited partner unit, and distributions of $502 million to common and preferred unitholders of the Predecessor. This was partially offset by sources of cash primarily related to $6,174 million of proceeds from the MPLX and ANDX Credit Agreements, $2.0 billion of net proceeds from the floating rate senior notes issued on September 9, 2019, $1.0 billion of net proceeds from the term loan, $9,313 million of net proceeds from draws on loan agreements with MPC, and $169 million from contributions from MPC and noncontrolling interests.
The change in financing activities was a $117 million use of cash in 2018 compared to a $171 million source of cash in 2017. For 2018, $44 million of the $117 million use of cash was due to the Merger. The remaining $73 million use of cash in 2018 primarily consisted of distributions to MPC of $4.1 billion for the acquisition of Refining Logistics and Fuels Distribution, the $4.1 billion repayment of the 364-day term loan facility, the $4,347 million repayment of borrowings under the MPC Loan Agreement, the $750 million redemption of the 5.5 percent senior notes due February 2023 and $14 million of related debt extinguishment charges, the $1,915 million repayment of the MPLX Credit Agreement, debt issuance costs and discounts of $76 million and $74 million respectively, distributions of $71 million and $17 million to preferred unitholders and noncontrolling interests respectively, and distributions of $1,819 million to unitholders and our general partner due mainly to the increase in units outstanding as well as an increase in the distribution per limited partner unit. This was partially offset by sources of cash primarily related to $1,410 million of proceeds from the MPLX Credit Agreement, $5.5 billion of net proceeds from the senior notes issued on February 8, 2018, $2.25 billion of net proceeds from the senior notes issued on November 15, 2018, $4.1 billion of net proceeds under the 364-day term loan facility that was drawn on February 1, 2018, and $3,962 million of net proceeds from draws on the MPC Loan Agreement.
The sources of cash in 2017 primarily consisted of $2.2 billion of net proceeds from the senior notes issued in February 2017, $670 million of proceeds under the bank revolving credit facility, $129 million in contributions from noncontrolling interests, and $483 million of net proceeds from sales of common units under the ATM Program. These items were partially offset by distributions to MPC of $1.9 billion for the acquisition of HST, WHC and MPLXT and the Joint-Interest Acquisition, $250 million repayment of the term loan facility, $165 million repayment of the bank revolving credit facility, distributions of $65 million to preferred unitholders, and distributions of $1.1 billion to unitholders and our general partner.
Long-term debt borrowings and repayments were a net $1.2 billion source of cash in 2019 compared to a $6.5 billion source of cash in 2018 and a $2.5 billion source of cash in 2017. During 2019, we used proceeds from the term loan and floating rate senior notes issued during the year to pay off ANDX’s credit facilities, repay ANDX’s senior notes maturing in 2019 and for general business purposes. During 2018, we used proceeds from senior notes issued during the year to redeem $750 million of 5.5 percent senior notes due February 2023, for the acquisition of Refining Logistics and Fuels Distribution and to repay amounts outstanding under the MPLX Credit Agreement and MPC Loan Agreement, as well as for general business purposes. During 2017, we used proceeds from the issuance of the February 2017 senior notes and MPLX Credit Agreement for general business purposes, including the acquisitions of HST, WHC, MPLXT and the Joint-Interest Acquisition from MPC, the acquisition of our equity interest in MarEn Bakken, the acquisition of the Ozark pipeline and capital expenditures.
Debt and Liquidity Overview
Credit Agreements
On July 30, 2019, in connection with the closing of the Merger, we amended our previously existing revolving credit facility (the “MPLX Credit Agreement”) to, among other things, increase the borrowing capacity from $2.25 billion to $3.5 billion and extend its maturity from July 2022 to 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 2019, we borrowed $5,310 million under the MPLX Credit Agreement, at an average interest rate of 3.547 percent, and repaid $5,310 million of borrowings
under the MPLX Credit Agreement. At December 31, 2019, we had no outstanding borrowings under this facility and had less than $1.0 million in letters of credit outstanding, resulting in total availability of approximately $3.5 billion, or almost 100 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 and 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, 2019, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.9 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.
Prior to the Merger, ANDX had revolving credit facilities (the “ANDX credit facilities”) totaling $2.1 billion in borrowing capacity, which were set to mature January 29, 2021. The ANDX credit facilities were terminated upon closing of the Merger and repaid with borrowings under the MPLX revolving credit facility. During the year ended December 31, 2019, there were borrowings of $864 million under the ANDX credit facilities, at an average interest rate of 4.129 percent, and repayments of $2.1 billion.
For further discussion, see Item 8. Financial Statements and Supplementary Data - Note 17.
Term Loan
On September 26, 2019, MPLX entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1.0 billion. Borrowings under the Term Loan Agreement bear 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). Amounts borrowed under the Term Loan Agreement are due and payable on September 26, 2021. As of December 31, 2019, MPLX had drawn the full $1.0 billion available on the term loan at an average interest rate of 2.561 percent. The proceeds from the borrowings were used to repay existing indebtedness and for general business purposes.
The Term Loan Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider to be customary for an agreement of this type and are substantially similar to those contained in the MPLX Credit Agreement, including a covenant that requires MPLX’s ratio of Consolidated Total Debt to Consolidated EBITDA (as both terms are defined in the Term Loan Agreement) for the four prior fiscal quarters not to exceed 5.0 to 1.0 as of the last day of each fiscal quarter (or during the six-month period following certain acquisitions, 5.5 to 1.0). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period.
Senior Notes
As of December 31, 2019, we had $19.1 billion in aggregate principal amount of senior notes outstanding. The increase compared to year-end 2018 resulted primarily from the assumption of ANDX’s senior notes and the issuance of variable rate senior notes as discussed below. As of December 31, 2019, minimum principal payments due during the next five years include $1.0 billion to repay our floating rate notes due September 2021, $1.0 billion to repay our floating rate notes due September 2022, $300 million to repay our 6.250 percent senior notes due October 2022, $500 million to repay our 3.500 percent senior notes due December 2022, $500 million to repay our 3.375 percent senior notes due March 2023, $1.0 billion to repay our 4.500 percent senior notes due July 2023, $450 million to repay our 6.375 percent senior notes due May 2024 and $1.15 billion to repay our 4.875 percent senior notes due December 2024.
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 are callable, in whole or in part, at par plus accrued and unpaid interest at any time on or after September 10, 2020. The proceeds were used to repay MPLX’s existing indebtedness and for general business purposes. Interest on the Floating Rate Senior Notes is payable quarterly in March, June, September and December, commencing on December 9, 2019. The interest rate applicable to the floating rate senior notes due September 2021 is LIBOR plus 0.9 percent per annum. The interest rate applicable to the floating rate senior notes due September 2022 is LIBOR plus 1.1 percent per annum.
In connection with the Merger, MPLX assumed ANDX’s outstanding senior notes, which had an aggregate principal amount of $3.75 billion, interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, approximately $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of approximately $3.06 billion new senior notes (the “Exchange Notes”) issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving approximately $690 million aggregate principal of outstanding senior notes issued by ANDX. Of this, $500 million aggregate principal amount was related to 5.5 percent senior notes due 2019. The aggregate principal amount of $500 million and accrued interest of $13.75 million was paid on October 15, 2019 at maturity using net proceeds from the issuance of the Floating Rate Senior Notes and borrowings under the Term Loan Agreement discussed above and includes interest through the payoff date. The Exchange Notes consist of $266 million in aggregate principal amount of 6.25 percent senior notes due October 2022, $486 million in aggregate principal amount of 3.5 percent senior notes due December 2022, $381 million in aggregate principal amount of 6.375 percent senior notes due May 2024, $708 million in aggregate principal amount of 5.25 percent senior notes due January 2025, $732 million in aggregate principal amount of 4.25 percent senior notes due December 2027 and $487 million in aggregate principal amount of 5.2 percent senior notes due December 2047.
For further discussion, see Item 8. Financial Statements and Supplementary Data - Note 17.
Our intention is to maintain an investment grade credit profile. As of February 1, 2020, the credit ratings on our senior unsecured debt were at or above investment grade level as follows:
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 and the Term Loan Agreement, which may limit our flexibility to obtain future financing.
Our liquidity totaled $4.4 billion at December 31, 2019, consisting of:
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, acquisitions, contractual obligations, and quarterly cash distributions. We may, from time to time, repurchase notes in the open market, in privately-negotiated transactions or otherwise in such volumes, at such prices and upon such other terms as we deem appropriate.
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, 2019:
For more details on equity activity, see Item 8. Financial Statements and Supplementary Data - Notes 8 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, 2019, 2018 and 2017 were $81 million, $71 million and $65 million, respectively.
On September 20, 2019, certain holders exercised their right to convert a total of 1.2 million Series A preferred units into common units. As a result of the transaction, approximately 29.6 million Series A preferred units remain outstanding as of December 31, 2019.
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”). The Series B preferred units are pari passu with the Series A preferred units with respect to distribution rights and rights upon liquidation. 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 year ended December 31, 2019 were $21 million.
Class B Units
On July 1, 2016, the previously outstanding 3,990,878 Class B units each automatically converted into 1.09 MPLX LP common units and the right to receive $6.20 per unit in cash. MPC funded the $6.20 per unit cash payment, which reduced our liability payable to Class B unitholders by approximately $25 million on July 1, 2016. In connection with the Class B conversion on July 1, 2016, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest. On July 1, 2017, all of the remaining 3,990,878 Class B units each automatically converted into 1.09 MPLX LP common units and the right to receive $6.20 per unit in cash. MPC funded this cash payment, which reduced our liability payable to Class B unitholders by approximately $25 million on July 1, 2017. In connection with the Class B units conversion on July 1, 2017, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its then two percent general partner interest. As common units outstanding as of the August 7, 2017 record date, the converted Class B units participated in the second quarter 2017 distribution.
GP/IDR Exchange
On February 1, 2018, our general partner’s IDRs were eliminated and its two percent economic general partner interest in MPLX LP was converted into a non-economic general partner interest, all in exchange for 275 million newly-issued MPLX LP common units. As a result of this transaction, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from MPLX.
ATM Program
On March 13, 2018, MPLX entered into a Third Amended and Restated Distribution Agreement providing for the at-the-market issuances of common units having an aggregate offering price of up to approximately $1.7 billion, in amounts, at prices and on terms determined by market conditions and other factors at the time of the offerings. There were no issuances made under the ATM Program during the years ended December 31, 2019 or December 31, 2018. In 2017, the sale of common units under the ATM Program generated net proceeds of approximately $473 million. MPLX used the net proceeds from sales under the ATM Program for general business purposes, including repayment or refinancing of debt and funding for acquisitions, working capital requirements and capital expenditures.
Distributions
We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $278 million per quarter, or $1,111 million per year, based on the number of common units. On January 23, 2020, we announced that the board of directors of our general partner had declared a distribution of $0.6875 per common unit that was paid on February 14, 2020 to common unitholders of record on February 4, 2020. This represents a 6 percent increase over the fourth quarter 2018 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.
In connection with MPLX’s acquisition of ANDX, MPC waived $12.5 million in quarterly distributions. The waiver was instituted in 2017 under the terms of ANDX's historical partnership agreement and was to remain in effect through 2019, the original term of the waiver agreement. This resulted in total waived distributions by MPLX in 2019 of $37.5 million.
MPC also agreed to waive the fourth quarter 2017 distributions on the common units issued in connection with the acquisition of Refining Logistics and Fuels Distribution, which took place on February 1, 2018. MPC also agreed to waive the portion of the fourth quarter 2017 distributions on common units received on February 1, 2018 in the GP/IDR Exchange in excess of what would have been distributable to MPC for its economic general partner interest, including IDRs, absent the exchange. Together, the value of these waived distributions was $135 million.
Additionally, in connection with our acquisition of a partial, indirect equity interest in the Bakken Pipeline system on February 15, 2017, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters beginning with the distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated from the acquisition date. This waiver is no longer applicable as a result of the GP/IDR Exchange on February 1, 2018.
The allocation of total quarterly cash distributions to general and limited partners is as follows for the years ended December 31, 2019, 2018 and 2017. 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 7.
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. Due to the waiver mentioned above, 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.
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 to increase 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 the acquisition of equipment or the construction costs and the development or acquisition of additional pipeline, 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:
(1)
Includes capital expenditures of the Predecessor for all periods presented.
(2)
This amount is represented in the Consolidated Statements of Cash Flows as Additions to property, plant and equipment after excluding growth and maintenance reimbursements. Reimbursements are shown as Contributions from MPC within the Financing activities section of the Consolidated Statements of Cash Flows.
(3)
Amount excludes contributions from noncontrolling interests of $95 million, $11 million and $129 million for the years ended December 31, 2019, 2018 and 2017, respectively, as reflected in the financing section of our Consolidated Statements of Cash Flows.
Our organic growth capital plan for 2020 is $1.5 billion. The L&S organic growth capital plan includes the continued expansion of the Mt. Airy Terminal in addition to projects which increase our long-haul crude oil, natural gas and NGL pipeline transportation capabilities. Many of our projects also increase our export capabilities, which provides for additional flexibility and competitive advantages in how we operate our assets as these projects further enhance our L&S segment full value chain capture. The G&P segment organic growth capital plan includes the addition of approximately 580 MMcf/d of processing capacity at three gas processing plants, one in the Marcellus region and two in the Southwest region. The G&P segment capital plan also includes the addition of approximately 80 mbpd of fractionation capacity in the Marcellus and Utica regions. We continuously evaluate our capital plan and make changes as conditions warrant.
Contractual Cash Obligations
The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2019:
(1)
Amounts represent outstanding borrowings at December 31, 2019, plus any commitment and administrative fees and interest.
(2)
Amounts relate primarily to facilities and equipment under leases, including ground leases, building space, office and field equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data - Note 22 for further discussion about our lease obligations.
(3)
Represents purchase orders and contracts related to the purchase or build out of property, plant and equipment.
(4)
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, 2019 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 for two successive five-year terms after 2022, which is not included in the natural gas purchase obligations line item.
(5)
Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data - Note 23 for further discussion of the product supply agreement).
(6)
Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from four to 20 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.
(7)
Excludes estimated accretion expense of $24 million. The total amount to be paid is approximately $51 million.
(8)
Other contracts include various service agreements and easements including right of way obligations.
In addition to the obligations included in the table above, we have omnibus agreements and employee services agreements with MPC. 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. The omnibus agreement remains in full force and effect as long as MPC controls our general partner.
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 services 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 $1,787 million of costs under the omnibus and employee services agreements for 2019.
Off-Balance Sheet Arrangements
As of December 31, 2019, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.
Effects of Inflation
Inflation did not have a material impact on our results of operations for the years ended December 31, 2019, 2018 or 2017. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire, build or replace property, plant and equipment. It may also 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 all or a portion of increased costs to our customers in the form of higher fees.
TRANSACTIONS WITH RELATED PARTIES
As of December 31, 2019, MPC owned our general partner and an approximate 62.9 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 other. 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. We believe that transactions with related parties are conducted under terms comparable to those with unrelated parties. 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 revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 54 percent, 48 percent and 36 percent of our total revenues and other income for 2019, 2018 and 2017, respectively. Of our total costs and expenses, MPC accounted for 24 percent, 27 percent and 22 percent for 2019, 2018 and 2017, 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 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:
(1)
These amounts include spending charged against remediation reserves, where permissible, but 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 $66 million in 2020. 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.
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.
We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections.
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 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.
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. 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. As of December 31, 2019, we had a total of $9.5 billion of goodwill recorded on the Consolidated Balance Sheets associated with all but one of our six reporting units.
Prior to performing our annual impairment assessment as of November 30, 2019, MPLX had goodwill totaling approximately $10.7 billion. As part of that assessment, MPLX recorded approximately $1,197 million of impairment expense in the fourth quarter of 2019 related to our Western G&P reporting unit within the G&P operating segment, which brought the amount of goodwill recorded within this reporting unit to zero. 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. For the remaining reporting units with goodwill, we determined that no significant adjustments to the carrying value of goodwill were necessary. The annual impairment assessment resulted in the fair value of the reporting units exceeding their carrying value by percentages ranging from approximately 8 percent to 457 percent. The reporting unit whose fair value exceeded its carrying amount by 8 percent, our Crude Gathering reporting unit, had goodwill totaling $1.1 billion at December 31, 2019. The operations which make up this reporting unit were acquired through the merger with ANDX. MPC accounted for its October 1, 2018 acquisition of Andeavor (including acquiring 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 has been treated as a common control transaction, which required the recognition of assets acquired and liabilities assumed using MPC’s historical carrying value. As such, given the short amount of time from when fair value was established to the date of the annual impairment test, the amount by which the fair value exceeded the carrying value within this reporting unit is not unexpected. Our Eastern G&P reporting unit had fair value exceeding its carrying value of approximately 18 percent and had goodwill totaling $1.8 billion as of December 31, 2019. An increase of one percentage point to the discount rate used to estimate the fair value of this reporting unit would not have resulted in goodwill impairment as of November 30, 2019. No other reporting units had had fair values exceeding carrying values of less than 20 percent.
Significant assumptions used to estimate the reporting units’ fair value included estimates of future cash flows and market information for comparable assets. If estimates for future cash flows, which are impacted primarily by producer customers’ development plans, which impact future volumes and capital requirements, were to decline, the overall reporting units’ fair value would decrease, resulting in potential goodwill impairment charges. 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 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. During the fourth quarter of 2019, two of the 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. For one of the joint ventures, we also had a basis difference, which was being amortized over the life of the underlying assets. As a result of the impairment recorded by the joint venture, we also assessed this basis difference for impairment and recorded approximately $14 million of impairment during the quarter related to this investment, which was recorded through “Income from equity method investments”. This impairment was largely due to a reduction in forecasted volumes of the joint venture related to the loss of one of its customers. At December 31, 2019, we had $5.3 billion 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 assumptions may be offset by favorable adjustments in other assumptions.
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.
Acquisitions
In accounting for business combinations, acquired assets, assumed liabilities and contingent consideration are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other assets and liabilities. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance.
The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach, which uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.
See Item 8. Financial Statements and Supplementary Data - Note 4 for additional information on our acquisitions, which includes a discussion of common control transactions and the related impact of how
such transactions are recorded. See Item 8. Financial Statements and Supplementary Data - Note 15 for additional information on fair value measurements.
Derivatives
We record all derivative instruments at fair value on the Consolidated Balance Sheets. To the extent that we have any, our crude oil and natural gas commodity derivatives are Level 2 financial instruments. Our NGL commodity derivatives and any option contracts are Level 3 financial instruments due to option volatilities and NGL prices that are interpolated and extrapolated due to inactive markets. Substantially all of our commodity derivative instruments are traded in OTC markets and are appropriately adjusted for non-performance risk.
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 2022. The customer has the unilateral option to extend the agreements for two consecutive five-year terms through December 2032. For accounting purposes, the natural gas purchase commitment and term extending options have been aggregated into a single compound embedded derivative which is a Level 3 financial instrument and is appropriately adjusted for non-performance risk (the “Natural Gas Embedded Derivative”). The significant unobservable inputs to the valuation of the Natural Gas Embedded Derivative include:
•
Probability of Renewal. As of December 31, 2019, we believe there is a 94 percent and 83 percent probability that the customer will exercise its first and second term extending options, respectively. The customer must exercise the first term extending option in order for the second term extending option to become available.
•
Commodity Prices. Third-party forward price curves are not available after 2023, which requires us to extrapolate NGL and natural gas prices.
A ten percent difference in the estimated fair value of the Natural Gas Embedded Derivative at December 31, 2019 would have affected income before taxes by $6.0 million for the year ended December 31, 2019. If the probabilities of renewal for the Natural Gas Embedded Derivative were changed to 84 percent and 73 percent, the liability would have been reduced by $5.0 million as of December 31, 2019. If the probabilities of renewal for the Natural Gas Embedded Derivative were changed to 99 percent and 87 percent, the liability would have been increased by $2.3 million as of December 31, 2019. Fair value estimation for all our derivative instruments is discussed in Item 8. Financial Statements and Supplementary Data - Note 15 and Note 16. Additional information about derivatives and their valuation may be found in Item 7A.
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, 2019, we did not have any open financial derivative instruments to economically hedge the risks related to interest rate fluctuations or commodity derivative instruments to economically hedge the risks related to the volatility of commodity prices; however, we continually monitor the market and our exposure and may enter into these arrangements in the future. While there is a risk related to changes in fair value of derivative instruments we may enter into; such risk is mitigated by price or rate changes related to the underlying commodity or financial transaction.
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 OTC 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. A separate agreement with certain counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. 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 2022. The customer has the unilateral option to extend the agreement for two consecutive five-year terms through December 2032. For accounting purposes, the natural gas purchase commitment and term extending options have been aggregated into a single compound embedded derivative. The probability of the customer exercising its options is determined based on assumptions about the customer’s potential business strategy decision points that may exist at the time they would elect 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. As of December 31, 2019 and 2018, the estimated fair value of this contract was a liability of $60 million and $61 million, respectively.
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, 2019 would not have affected income before income taxes for the year ended December 31, 2019, 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 long-term 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.
(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, 2019.
(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, 2019.
At December 31, 2019, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate instruments including our term loan, floating rate senior notes and our revolving credit facility. We had no outstanding balance under the revolving credit facility at December 31, 2019. The fair value of our fixed-rate debt is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value. Interest rate fluctuations generally do not impact the fair value of borrowings under our bank revolving credit or term loan facilities, but may affect our results of operations and cash flows. As of December 31, 2019, we did not have any commodity or financial derivative instruments to hedge the risks related to commodity price or interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements in the future.
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 would allow us to pass those losses through to our customers, thus reducing our risk, when we are selling NGLs and acting as our producer customers’ agent. 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.
We would also be subject to risk of loss resulting from non-payment or non-performance by the counterparties to our derivative contracts. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value at the reporting date. Outstanding instruments expose us to credit loss in the event of non-performance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate non-performance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.
Item 8.
Item 8. Financial Statements and Supplementary Data
INDEX
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/ Pamela K.M. Beall
/s/ C. Kristopher Hagedorn
Michael J. Hennigan
Director, President and Chief Executive Officer of MPLX GP LLC
(the general partner of MPLX LP)
Pamela K.M. Beall
Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
C. Kristopher Hagedorn
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, 2019.
The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2019 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/ Pamela K.M. Beall
Michael J. Hennigan
Director, President and Chief Executive Officer of MPLX GP LLC
(the general partner of MPLX LP)
Pamela K.M. Beall
Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
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, 2019 and 2018, and the related consolidated statements of income, comprehensive income, equity and cash flows for each of the three years in the period ended December 31, 2019, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 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, 2019, 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 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 Tests - Eastern and Western Gathering and Processing and Crude Gathering Reporting Units
As described in Notes 2 and 14 to the consolidated financial statements, the Company’s consolidated goodwill balance was $9.5 billion as of December 31, 2019. As disclosed by management, of that amount, the goodwill associated with the Eastern Gathering and Processing reporting unit amounted to $1.8 billion and goodwill associated with the Crude Gathering reporting unit amounted to $1.1 billion. In addition, an impairment charge of $1.2 billion was recorded in 2019 related to the Western Gathering and Processing reporting unit, which brought the amount of goodwill recorded within this reporting unit to zero. Management conducts impairment tests as of November 30 of each year or more frequently if events or circumstances indicate that reporting unit carrying values of goodwill may be impaired. As a result of a change in reporting units during 2019, management performed impairment tests on these reporting units prior to and immediately following the change in reporting units. The fair value of each reporting unit is determined using a combination of income and market approach methods. The significant assumptions that were used to develop the estimates of the fair values of each reporting unit under the income approach include 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 consideration for our determination that performing procedures relating to the goodwill impairment tests of the Company’s Eastern Gathering and Processing, Western Gathering and Processing, and Crude Gathering reporting units, as well as certain related reporting units prior to the change, is a critical audit matter as there was significant judgment by management when estimating the fair values of the reporting units. This in turn led to a high degree of auditor judgment, subjectivity, and effort in performing audit procedures and evaluating evidence related to management’s fair value estimates and significant assumptions related to producer customers’ development plans, which impact future volumes and capital requirements.
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 tests, including controls over the estimation of the fair values of the Eastern Gathering and Processing, Western Gathering and Processing, and Crude Gathering reporting units. These procedures also included, among others, testing management’s process for developing the fair value estimates; evaluating the appropriateness of the valuation methods used; testing the completeness and accuracy of underlying data used by management; and evaluating the reasonableness of significant assumptions related to producer customers’ development plans, which impact future volumes and capital requirements used in determining the fair values of each reporting unit under the income approach. Professionals with specialized skill and knowledge were utilized to assist in evaluating
the appropriateness of the Company’s income and market approach methods. Evaluating the assumptions related to producer customers’ development plans, which impact future volumes and capital requirements involved (i) considering whether the assumptions used were reasonable considering past performance of each reporting unit, producer customers’ historical and future production volumes, historical and approved future capital projects, and industry outlook reports, and (ii) considering whether the assumptions were consistent with evidence obtained in other areas of the audit.
/s/PricewaterhouseCoopers LLP
Toledo, Ohio
February 28, 2020
We have served as the Company’s auditor since 2012.
MPLX LP
Consolidated Statements of Income
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of Comprehensive Income
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Balance Sheets
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of Equity
The accompanying notes are an integral part of these consolidated financial statements.
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 transportation, storage and distribution of crude oil, asphalt and refined petroleum 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 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 and refined petroleum 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 30, 2019, MPLX completed its acquisition by merger (the “Merger”) of Andeavor Logistics LP (“ANDX”). At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. See Note 4 for additional information regarding the Merger.
Basis of Presentation - 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. 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. The accompanying consolidated financial statements of MPLX have been prepared in accordance with GAAP.
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 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; recognizing share-based compensation expense; estimating revenues, expense accruals and capital expenditures; valuing AROs; 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, 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 annual payments or fixed demand charges.
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.
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. Restricted cash is included in “Other current assets” on the Consolidated Balance Sheets.
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 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.
Lease Receivables - Lease receivables are the present value of the sum of the future minimum lease payments and the unguaranteed residual value of the leased assets under arrangements where MPLX is the lessor. Management assesses these lease receivables for recoverability quarterly.
Inventories - Inventories consist primarily of natural gas, propane, other NGLs and materials and supplies to be used in operations. Natural gas, propane, and other NGLs are valued at the lower of cost or market value. Materials and supplies are stated at the lower of cost or market value. Cost for materials and supplies are determined primarily using the weighted-average cost method.
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.
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.
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. Intangibles not subject to amortization are tested for impairment annually and when circumstances indicate that the fair value is less than the carrying amount of the intangible. If the fair value is less than the carrying value, an impairment is recorded for the difference.
As a result of MPLX’s November 30, 2019 annual goodwill impairment analysis, we recorded an impairment charge of approximately $1.2 billion, which resulted in a goodwill balance of $9.5 billion at December 31, 2019. See Note 14 for further details. No impairments were recorded as a result of our 2018 annual goodwill impairment analysis.
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. MPLX recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. 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.
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. During the fourth quarter of 2019, two of the 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. For one of the joint ventures, we also had a basis difference which was being amortized over the life of the underlying assets. As a result of the impairment recorded by the joint venture, we also assessed this basis difference for impairment and recorded approximately $14 million of impairment during the quarter related to this investment, which was recorded through “Income from equity method investments”. This impairment was largely due to a reduction in forecasted volumes of the joint venture related to the loss of one of its customers.
Deferred Financing Costs - Deferred financing costs are an asset for credit facility costs and netted against debt for senior notes. These costs are amortized over the contractual term of the related obligations using the effective interest method or, in certain circumstances, accelerated if the obligation is refinanced.
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 instruments under the captions “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.
During the years ended December 31, 2019, 2018 and 2017, MPLX did not elect hedge accounting for any derivatives. MPLX has 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 of Financial Instruments - Management believes the carrying amount of financial instruments, including cash and cash equivalents, receivables, receivables from related parties, other current assets, accounts payable, accounts payable to related parties and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximate fair value due to the variable interest rate that approximates current market rates (see Note 15). Derivative instruments are recorded at fair value, based on available market information (see Note 16).
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 its share-based compensation plan as described further in Note 21. 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.
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 and use a Monte Carlo valuation model to calculate a grant date fair value.
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.
Tax Effects of Share-Based Compensation - MPLX elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. Additional paid-in capital is reported as “Common unitholders - public” on the accompanying Consolidated Balance Sheets.
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 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 8 and 9, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued as a liability until declared. However, when distributions related to the eliminated IDRs were made, earnings equal to the amount of those distributions were first allocated to the general partner before the remaining earnings are allocated to the limited partner unitholders based on 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 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, general partner units, Series A and Series B preferred units, certain equity-based compensation awards and eliminated IDRs. Class B units were considered to be a separate class of common units that did not participate in distributions.
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. However, prior to 2018 when distributions related to the eliminated IDRs were made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders, except Class B unitholders, based on their respective ownership percentages. Subsequent to the conversion of the general partner to a non-economic interest as described in Note 8, no earnings are allocated to the general partner. Distributions, although earned, are not accrued until declared. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 7.
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, preferred units, and eliminated IDRs, 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, NGL 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. 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.
Accounting for Changes in Ownership Interests in Subsidiaries - MPLX’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest or acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale results in a loss of control, it would result in the deconsolidation of a subsidiary with a gain or loss recognized on the Consolidated Statements of Income unless the subsidiary meets the definition of in-substance real estate. Deconsolidation of in-substance real estate is recorded at cost with no gain or loss recognized. If the purchase of additional interest occurs that changes the acquirer’s ownership interest from noncontrolling to controlling, the acquirer’s preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination.
3. Accounting Standards
Recently Adopted
ASU 2016-02, Leases
We adopted ASU No. 2016-02, Leases (Topic 842), as of January 1, 2019, electing the transition method, which permits entities to adopt the provisions of the standard using the modified retrospective approach without adjusting comparative periods. We also 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 have 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.
Adoption of the new standard resulted in the recording of ROU assets and lease liabilities of approximately $629 million and $629 million, respectively, as of January 1, 2019. This is inclusive of ROU assets and lease liabilities related to ANDX of $124 million and $127 million, respectively. The standard did not materially impact our consolidated statements of income, cash flows or equity as a result of adoption.
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 22 for further information regarding our ongoing evaluation of the impacts of lease reassessments as modifications occur.
ASU 2017-04, Intangibles - Goodwill and Other - Simplifying the Test for Goodwill Impairment
In connection with our annual goodwill impairment test, we adopted ASU 2017-04 prospectively during the fourth quarter of 2019. Under ASU 2017-04, the recognition of an impairment charge is calculated based on the amount by which the carrying amount exceeds the reporting unit’s fair value, which could be different from the amount calculated under the former method using the implied fair value of the goodwill; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. During the fourth quarter of 2019, we recorded certain goodwill impairment charges as described in Note 14.
We also adopted the following standard during 2019, which did not have a material impact to our financial statements or financial statement disclosures:
Not Yet Adopted
ASU 2016-13, Credit Losses - Measurement of Credit Losses on Financial Instruments
In June 2016, the FASB issued an ASU related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses be based on an expected loss approach which includes estimates of losses over the life of exposure that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The application of this ASU will not have a material impact on our consolidated financial statements.
4. Acquisitions
Acquisition of Andeavor Logistics LP
On May 7, 2019, ANDX, Tesoro Logistics GP, LLC, then the general partner of ANDX (“TLGP”), 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 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 8 for information on common units issued in connection with the Merger as well as Series B preferred units.
Additionally, as a result of the Merger, each ANDX TexNew Mex Unit issued and outstanding immediately prior to the effective time of the Merger was converted into a right for Western Refining Southwest, Inc. (“Southwest, Inc.”), a wholly-owned subsidiary of MPC, as the holder of all such units, to receive a unit representing a substantially equivalent limited partner interest in MPLX (the “MPLX TexNew Mex Units”). By virtue of the conversion, all ANDX TexNew Mex Units were cancelled and ceased to exist as of the effective time of the Merger. The MPLX TexNew Mex Units are a new class of units in MPLX substantially equivalent to the ANDX TexNew Mex Units, including substantially equivalent rights, powers, duties and obligations that the ANDX TexNew Mex Units had immediately prior to the closing of the Merger. 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 Southwest Inc., 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 8.
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 (including acquiring 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. The fair value of assets acquired and liabilities assumed shown below represents MPC’s historical carrying values as of October 1, 2018.
(1)
Inclusive of activity recorded subsequent to the acquisition of ANDX on July 30, 2019, a portion of which was recorded as a non-cash contribution from MPC.
(2)
Includes both related party and third party other current assets.
(3)
Includes approximately $4 million of favorable lease assets. In connection with the implementation of ASC 842, this balance was reclassed to “Right of use assets” on the Consolidated Balance Sheets during 2019.
(4)
Includes both related party and third party other noncurrent assets as well as right of use assets associated with leases.
(5)
Includes accrued liabilities, operating lease liabilities, long-term debt due within one year, as well as related party and third party other current liabilities.
(6)
Includes deferred revenue and deferred income taxes, as well as related party and third party other noncurrent liabilities.
Details of our valuation methodology and significant inputs for fair value measurements are included by asset class below. The fair value measurements for equity method investments; property, plant and equipment; intangible assets and long-term debt are based on significant inputs that are not observable in the market and, therefore, represent Level 3 measurements.
Goodwill
The purchase consideration allocation resulted in the recognition of $8.2 billion in goodwill, which has been allocated between the L&S segment and the G&P segment at $7.2 billion and $1.0 billion, respectively. See Note 14 for further information related to goodwill.
Inventory
The fair value of inventory was recorded at cost as of October 1, 2018, as these items are related to spare parts as well as materials and supplies and approximate fair value.
Equity Method Investments
The fair value of the equity method investments was $642 million, which was determined based on applying income and market approaches. The income approach relied on the discounted cash flow method and the market approach relied on a market multiple approach considering historical and projected financial results. Discount rates for the discounted cash flow models were based on capital structures for similar market participants and included various risk premiums that account for risks associated with the specific investments.
Property, Plant and Equipment
The fair value of property, plant and equipment was $6.3 billion, which was based primarily on the cost approach. Key assumptions in the cost approach include determining the replacement cost by evaluating recent purchases of similar assets or published data, and adjusting replacement cost for economic and functional obsolescence, location, normal useful lives, and capacity (if applicable).
Acquired Intangible Assets
The fair value of the acquired identifiable intangible assets was $1.0 billion, which represents the value of various customer contracts and relationships and other intangible assets. The fair value of customer contracts and relationships was $950 million, which was valued by applying the multi-period excess earnings method, which is an income approach. Key assumptions in the income approach include the underlying contract cash flow estimates, remaining contract term, probability of renewal, growth rates and discount rates. The intangible assets are all finite lived and will be amortized over two to 10 years.
Debt
The fair value of the ANDX notes was measured using a market approach, based upon the average of quotes for the acquired debt from major financial institutions and a third-party valuation service. Additionally, approximately $1.1 billion of borrowings under revolving credit agreements approximated fair value. The ANDX revolving credit facilities with total capacity of $2.1 billion were terminated upon closing of the Merger and were repaid with borrowings under the MPLX revolving credit facility.
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 $2,400 million 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. For the year ended December 31, 2018, we recognized $580 million of revenues and other income related to ANDX and $172 million of net income related to ANDX.
Pro Forma Financial Information
The following unaudited pro forma information combines the historical operations of MPLX and ANDX, giving effect to the Merger as if it had been consummated on January 1, 2018, the beginning of the earliest period presented.
The pro forma information includes adjustments to align accounting policies, which include adjustments for capitalization of assets and treatment of planned major maintenance costs. The pro forma information also includes adjustments related to: eliminating transactions between MPLX and ANDX, which previously would have been recorded as transactions between related parties; basis differences on equity method investments as a result of recognition of MPC’s investments in ANDX’s equity method investments; depreciation and amortization expense to reflect the increased fair value of property, plant and equipment and increased amortization expense related to identifiable intangible assets, as well as adjustments to interest expense for the amortization of fair value adjustments over the remaining term of ANDX’s outstanding debt, reversal of ANDX’s historical amortization of debt issuance costs and debt discounts and to adjust for the difference in the weighted average interest rate between MPLX’s revolving credit facility and ANDX’s revolving credit facilities.
The following table presents MPLX’s previously reported Consolidated Balance Sheet Data as of December 31, 2018 retrospectively adjusted for the Merger:
Mt. Airy Terminal
On September 26, 2018, MPLX acquired an eastern U.S. Gulf Coast export terminal (the “Mt. Airy Terminal”) from Pin Oak Holdings, LLC for total consideration of $451 million. At the time of the acquisition, the terminal included tanks with 4 million barrels of third-party leased storage capacity and a dock with 120 mbpd of capacity. The Mt. Airy Terminal is located on the Mississippi River between New Orleans and Baton Rouge, is in close proximity to several Gulf Coast refineries including MPC’s Garyville Refinery and is near numerous rail lines and pipelines. The Mt. Airy Terminal is accounted for within the L&S segment. In the first quarter of 2019, an adjustment to the initial purchase price was made for approximately $5 million related to the final settlement of the acquisition, which was paid in the first six months of 2019 as shown on the statement of cash flow. This reduced the total purchase price to $446 million and resulted in $336 million of property, plant and equipment, $121 million of goodwill and the remainder being attributable to net liabilities assumed.
Based on the fair value estimates of assets acquired and liabilities assumed at the acquisition date, the purchase price was allocated as follows:
Goodwill represents the significant growth potential of the terminal due to the multiple pipelines and rail lines which cross the property, the terminal’s position as an aggregation point for liquids growth in the region for both ocean-going export vessels and inland barges, the proximity of the terminal to MPC’s Garyville refinery and other refineries in the region as well as the opportunity to construct an additional dock at the site.
The amount of revenue and income from operations associated with the acquisition of the Mt. Airy Terminal included on the Consolidated Statement of Income since the September 26, 2018 acquisition date was not material to the financial statements. Assuming the acquisition had occurred on January 1, 2017, the consolidated pro forma results would not have been materially different from the reported results.
Refining Logistics and Fuels Distribution Acquisition
On February 1, 2018, MPC and MPLX LP closed on an agreement for the dropdown of refining logistics assets and fuels distribution services to MPLX LP. MPC contributed these assets and services in exchange for $4.1 billion in cash and a fixed number of MPLX LP common units and general partner units of 111,611,111 and 2,277,778, respectively. The fair value of the common and general partner units issued as of the acquisition date was $4.3 billion based on the closing common unit price as of February 1, 2018, as recorded on the Consolidated Statements of Equity, for a total purchase price of $8.4 billion. The equity issued consisted of: (i) 85,610,278 common units to MPLX GP LLC (“MPLX GP”), (ii) 18,176,666 common units to MPLX Logistics Holdings LLC (“MPLX Logistics”) and (iii) 7,824,167 common units to MPLX Holdings Inc. (“MPLX Holdings”). MPLX also issued 2,277,778 general partner units to MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in MPLX. MPC agreed to waive approximately one-third of the first quarter 2018 distributions on the common units issued in connection with this transaction. As a result of this waiver, MPC did not receive $23.7 million of the distributions that would have otherwise accrued on such common units with respect to the first quarter 2018. Immediately
following this transaction, the GP Interest was converted into a non-economic general partner interest as discussed in Note 8.
MPLX recorded this transaction on a historical basis as required for transactions between entities under common control. No effect was given to the prior periods as these entities were not considered businesses prior to the February 1, 2018 dropdown. In connection with the dropdown, approximately $830 million of net property, plant and equipment was recorded in addition to $85 million and $130 million of goodwill allocated to MPLX Refining Logistics LLC (“Refining Logistics”) and MPLX Fuels Distribution LLC (“Fuels Distribution”), respectively. Both the Refining Logistics assets and the Fuels Distribution services are accounted for within the L&S segment.
As of the transaction date, the Refining Logistics assets included 619 tanks with approximately 56 million barrels of storage capacity (crude, finished products and intermediates), 32 rail and truck racks, 18 docks, and gasoline blenders. These assets generate revenue through storage services agreements with MPC. Refining Logistics provides certain services to MPC related to the receipt, storage, throughput, custody and delivery of petroleum products in and through certain storage and logistical facilities and assets associated with MPC’s refineries.
Fuels Distribution, which is a wholly owned subsidiary of MPLXT, generates revenue through a Fuels Distribution Services Agreement with MPC. Fuels Distribution is structured to provide a broad range of scheduling and marketing services as MPC’s agent.
The amounts of revenue and income from operations associated with these investments included on the Consolidated Statements of Income, since the February 1, 2018 acquisition date, were as follows:
Joint-Interest Acquisition
On September 1, 2017, MPLX entered into a Membership Interests and Shares Contributions Agreement with MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, whereby MPLX agreed to acquire certain ownership interests in joint venture entities indirectly held by MPC. Pursuant to the agreement, MPC Investment agreed to contribute: all of the membership interests of Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension; all of the membership interests of MPL Louisiana Holdings LLC, which holds a 41 percent interest in LOOP; a 59 percent interest in LOCAP; and a 25 percent interest in Explorer, through a series of intercompany contributions to MPLX for an agreed upon purchase price of approximately $420 million in cash and equity consideration valued at approximately $630 million, for total consideration of $1.05 billion (collectively, the “Joint-Interest Acquisition”). The number of common units representing the equity consideration was then determined by dividing the contribution amount by the simple average of the ten-day trailing volume weighted average NYSE price of a common unit for the ten trading days ending at market close on August 31, 2017. The fair value of the common and general partner units issued was approximately $653 million based on the closing common unit price as of September 1, 2017, as recorded on the Consolidated Statements of Equity, for a total purchase price of $1.07 billion. The equity issued consisted of: (i) 13,719,017 common units to MPLX GP; (ii) 3,350,893 common units to MPLX Logistics and (iii) 1,441,224 common units to MPLX Holdings. MPLX also issued 377,778 general partner units to MPLX GP in order to maintain its two percent GP Interest in MPLX.
Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations. LOOP owns and operates midstream crude oil infrastructure, including a deep-water oil port offshore of Louisiana, pipelines and onshore storage facilities. LOOP also manages the operations of LOCAP, an affiliate pipeline system. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the Mid-Continent region of the United States. Explorer owns and operates an approximate 1,830-
mile common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast region to the Midwest United States. MPLX accounts for the Joint-Interest Acquisition entities as equity method investments within its L&S segment.
As a transfer between entities under common control, MPLX recorded the Joint-Interest Acquisition on its Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss. MPLX recognizes an “Accumulated other comprehensive loss” on its Consolidated Balance Sheets relating to pension and other post-retirement benefits provided by the LOOP and Explorer joint-interests to their employees. MPLX is not a sponsor of these benefit plans.
Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to periods prior to the acquisition were prorated on a daily basis with MPLX retaining the portion of distributions beginning on the closing date. All amounts distributed to MPLX related to periods before the acquisition have been paid to MPC. Additionally, MPLX agreed to pay MPC for any distributions of cash from LOOP related to the sale of LOOP’s excess crude oil inventory. Because the future distributions or payments could not be reasonably quantified, a liability was not recorded in connection with the acquisition. MPLX subsequently received distributions related to the time period prior to the acquisition, which it remitted to MPC and recorded a corresponding decrease to the general partner’s equity for $32 million.
MPLX accounts for the interests acquired in the Joint-Interest Acquisition one month in arrears, which is the most recently available information. The amount of income associated with these investments included on the Consolidated Statements of Income under the caption “Income from equity method investments” for the twelve months ended December 31, 2019, December 31, 2018 and December 31, 2017 totaled $110 million, $118 million and $21 million, respectively. MPC agreed to waive approximately two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive approximately two-thirds of the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.
Acquisition of Hardin Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC
MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Pursuant to a Membership Interests Contributions Agreement entered into on March 1, 2017 by MPLX with MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment (each a wholly-owned subsidiary of MPC), MPC Investment agreed to contribute the outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to MPLX for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million. The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten-day trailing volume weighted average NYSE price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million, and consisted of (i) 9,197,900 common units to MPLX GP, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. MPLX also issued 264,497 general partner units to MPLX GP in order to maintain its two percent GP Interest in MPLX. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the common units issued in connection with the Transaction. As a result of this waiver, MPC did not receive two-thirds of the general partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first quarter 2017 distributions. The value of these waived distributions was $6 million.
HST owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. As of the acquisition date, these pipeline systems consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines. WHC owns and operates eight butane and propane storage caverns located in Michigan with approximately 1.8 million barrels of NGL storage capacity. As of the acquisition date, MPLXT owned and operated 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products. Additionally, MPLXT operated one leased terminal and had partial ownership interest in two terminals. Collectively, these 62 terminals have a
combined shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States. MPLX accounts for these businesses within its L&S segment.
MPLX retrospectively adjusted the historical financial results for all periods to give effect to the acquisition of HST and WHC effective January 1, 2015, and the acquisition of MPLXT effective April 1, 2016, as required for transactions between entities under common control. Prior to these dates, these entities were not considered businesses and, therefore, there are no financial results from which to recast.
Acquisition of Ozark Pipeline
On March 1, 2017, MPLX acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for approximately $219 million, including purchase price adjustments made in the second quarter of 2017. Based on the final fair value estimates of assets acquired and liabilities assumed at the acquisition date, the purchase price was primarily allocated to property, plant and equipment. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting approximately 230 mbpd. MPLX accounts for the Ozark pipeline within its L&S segment.
The amounts of revenue and income from operations associated with the acquisition included on the Consolidated Statements of Income, since the March 1, 2017 acquisition date are as follows:
Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2017, the consolidated pro forma results would not have been materially different from reported results.
MarEn Bakken
On February 15, 2017, MPLX closed on a joint venture, MarEn Bakken Company, LLC (“MarEn Bakken”), with Enbridge Energy Partners L.P. in which MPLX LP acquired a partial, indirect interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. and Sunoco Logistics Partners, LP. The Bakken Pipeline system is capable of transporting more than 520 mbpd of crude oil from the Bakken/Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. MPLX contributed $500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a 37 percent indirect interest in the Bakken Pipeline system. MPLX holds, through a subsidiary, a 25 percent interest in MarEn Bakken, which equates to an approximate 9 percent indirect interest in the Bakken Pipeline system.
MPLX accounts for its investment in MarEn Bakken as an equity method investment and bases the equity method accounting for this joint venture one month in arrears which is the most recently available information. The amount of income or loss associated with these investments included on the Consolidated Statements of Income under the caption “Income from equity method investments” for the twelve months ended December 31, 2019, December 31, 2018 and December 31, 2017 totaled $72 million, $48 million and $15 million, respectively. In connection with MPLX’s acquisition of a partial, indirect equity interest in the Bakken Pipeline system, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters, beginning with distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated to $0.8 million from the acquisition date. This waiver is no longer applicable as a result of the conversion of the GP Interest to a non-economic general partner interest as discussed in Note 8.
5. Investments and Noncontrolling Interests
The following table presents MPLX’s equity method investments at the dates indicated:
(1)
These investments as well as certain investments included within “Other” for both L&S and G&P are investments acquired as part of the Merger. The December 31, 2019 balance reflects all purchase accounting adjustments identified by MPC as part of its acquisition of Andeavor.
As a result of the Merger, MPLX acquired an ownership interest in Rendezvous Gas Services, L.L.C. (“RGS”), Minnesota Pipe Line Company, LLC (“MNPL”) and Andeavor Logistics Rio Pipeline LLC (“ALRP”), among others. RGS and ALRP have been deemed to be VIEs; however, neither MPLX nor any of its subsidiaries have been deemed to be the primary beneficiary due to voting rights on significant matters. For all of the investments acquired through the Merger, we have the ability to exercise influence through participation in the management committees which make all significant decisions. However, since we have equal or proportionate 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, 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.
In addition to the investments acquired through the Merger, MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”), Sherwood Midstream LLC (“Sherwood Midstream”), MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”) and Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”) are also deemed to be VIEs. However, consistent with the investments above, neither MPLX nor any of its subsidiaries are deemed to be the primary beneficiary due to voting rights on significant matters. Sherwood Midstream has been deemed the primary beneficiary of 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, 2019, MPLX has a 23.7 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream. During 2019, MPLX acquired equity interests in Whistler Pipeline LLC and Wink to Webster Pipeline LLC. Both joint ventures are located in the Permian Basin and will transport crude oil or natural gas to the U.S. Gulf Coast. These investments are deemed to be VIEs; however, MPLX does not operate these joint ventures and is not deemed to be the primary beneficiary due to voting rights on significant matters as described above.
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, 2019, 2018 and 2017.
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. 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 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, 2019, 2018 and 2017 is as follows:
(1)
The financial information for equity method investments for 2019 includes financial information of equity method investments acquired as part of the Merger. The financial information for equity method investments for 2018 includes financial information of equity method investments acquired as part of the Merger for the last three months of 2018. The financial information for equity method investments for 2017 does not include financial information of equity method investments acquired as part of the Merger. See Note 1 for additional information.
(2)
“Income from equity method investments” includes the impact of any basis differential amortization or accretion.
Summarized balance sheet information for MPLX’s equity method investments as of December 31, 2019 and 2018 is as follows:
As of December 31, 2019 and 2018, the carrying value of MPLX’s equity method investments in the G&P segment exceeded the underlying net assets of its investees by $1.0 billion and $1.3 billion, respectively. As of December 31, 2019 and 2018, the carrying value of MPLX’s equity method investments in the L&S segment exceeded the underlying net assets of its investees by $329 million and $187 million, respectively. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets, except for $498 million and $167 million of excess related to goodwill for the G&P and L&S segments, respectively, as of December 31, 2019 and $542 million and $167 million of excess related to goodwill for the G&P and L&S segments, respectively, as of December 31, 2018.
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, 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 fuels distribution agreements with MPC under which MPC pays MPLX for marketing and selling MPC’s products. This can include MPC paying MPLX a tiered monthly fee based on the volume of products sold or thought margin support under a related product supply agreement. Agreements are subject to minimum volume commitments and are subject various terms and renewal periods.
•
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 six-year marine transportation agreement under which MPC pays MPLX fees for providing marine transportation of crude oil, feedstock and refined petroleum products, and related services.
•
MPLX has various trucking transportation services agreements with terms ranging from month-to-month to 10 years, under which MPC pays MPLX fees for gathering barrels and providing trucking, dispatch, delivery and data services. Most of these agreements are subject to minimum volume commitments and have various terms regarding carry-forward of deficiency payments as credits towards excess volumes shipped in future periods. These agreements are subject to various terms and renewal periods.
•
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 terms ranging from three to 17 years and are subject to various renewal periods.
•
MPLX has a 10-year terminal services agreement governing certain terminals under which MPC pays MPLX fees for terminal storage for refined petroleum products. Under this agreement MPC pays MPLX agreed upon fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is subject to minimum volume throughput commitments under which MPC pays a deficiency payment for any period in which they do not meet the minimum committed volume. The terminal services agreement with MPC includes automatic renewal terms ranging from one to five years. MPLX also has numerous additional terminal services agreements governing terminals acquired through the Merger. Under these agreements, MPC pays MPLX agreed upon fees relating to various terminal activities including throughput, blending, on and offloading and additives. Many of these agreements contain various minimum commitments for some or all of these activities. Some of these agreements allow for deficiency payments to be applied as credits to future periods with excess throughput volumes. These agreements have terms ranging from one to 10 years with varying renewal terms.
•
MPLX has a year to year keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGL’s related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity
risk. The pricing structure under this agreement provides for a base volume subject to a base rate and incremental volumes subject to variable rates which are calculated with reference to certain of our costs incurred as processor of the volumes. The pricing for both the base and incremental volumes are subject to revision each year.
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 one to five years in length and automatically renew unless terminated by either party.
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 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 have initial terms of 50 years.
Management Services Agreement
MPLX, through its subsidiary, HSM, has a management services agreement with MPC under which it provides management services to assist MPC in the oversight and management of the marine business. HSM receives a fixed annual fee for providing the required management services. This fee is adjusted annually on the anniversary of the contract for inflation and any changes in the scope of the management services provided. This agreement is set to expire on January 1, 2021 and automatically renews for two additional renewal terms of 5 years each 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. Certain environmental indemnifications related to the Los Angeles Logistics Assets Acquisition are excluded from coverage under omnibus agreements and are instead covered by a Carson Assets Indemnity Agreement.
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 with MPC Investment (the “MPC Loan Agreement”). Under the terms of the agreement, MPC Investment makes a loan or loans to MPLX on a revolving basis as requested by MPLX and as agreed to by MPC Investment. On April 27, 2018, MPLX and MPC Investment entered into an amendment to the MPC Loan Agreement to increase the borrowing capacity under the MPC Loan Agreement from $500 million to $1 billion. In connection with the Merger, on July 31, 2019, MPLX and MPC Investment entered into a second amendment to the MPC Loan Agreement to increase the borrowing capacity under the MPC Loan Agreement to $1.5 billion in aggregate principal amount of all loans outstanding at any one time. The entire unpaid principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), shall 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 July 31, 2024. 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 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 was as follows:
Prior to the Merger, ANDX was also party to a loan agreement with MPC (“ANDX-MPC Loan Agreement”). This facility was entered into on December 21, 2018, with a borrowing capacity of $500 million. In connection with the Merger, on July 31, 2019, MPLX repaid the entire outstanding balance and terminated the ANDX-MPC Loan Agreement. There was no activity on the ANDX-MPC Loan Agreement in 2018. Activity on the agreement during 2019 prior to the Merger was as follows:
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.
Revenue received from related parties included on the Consolidated Statements of Income was as follows:
(1)
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 2019, 2018 and 2017, these sales totaled $1,120 million, $607 million and $254 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. 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.
Expenses incurred from MPC under the omnibus and employee services agreements as well as other purchases from MPC included on the Consolidated Statements of Income are as follows:
Some charges incurred under the omnibus and ESA 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 2019, 2018 and 2017, these charges totaled $169 million, $152 million and $42 million, respectively.
Related Party Assets and Liabilities
From time to time, MPLX may also sell to or purchase from related parties assets and inventory at the lesser of average unit cost or net realizable value. Sales to related parties during the years ended December 31, 2019 and 2018 were $10 million and $6 million, respectively. Purchases from related parties during the years ended December 31, 2019 and 2018 were approximately $5 million and $8 million, respectively.
7. 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. Additional MPLX common units and MPLX Series B preferred units were issued on July 30, 2019 as a result of the merger with ANDX 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.
Classes of participating securities for 2019, 2018 and 2017 include:
The HST, WHC and MPLXT acquisitions and the Merger were transfers 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 2019 and 2018, MPLX had dilutive potential common units consisting of certain equity-based compensation awards. In 2017, MPLX had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Potential common units omitted from the diluted earnings per unit calculation for the years ended December 31, 2019, 2018 and 2017 were less than 1 million.
(1)
See Note 8 for distribution information.
(2)
Distributions declared on January 25, 2018 on general partner common units issued on February 1, 2018 in exchange for the economic general partner interest, including IDRs, are shown as general partner distributions declared.
(1)
Allocation of net income/(loss) attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the period.
(2)
The Series B preferred units and the MPLX common units issued in connection with the Merger were not outstanding during the entire year. See Notes 4 and 8 for additional information about the treatment of these units.
8. Equity
Units Outstanding - MPLX had 1,058,355,471 common units outstanding as of December 31, 2019. Of that number, 665,997,540 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, 2019. The sections below describe activities and events which impacted our unit balances throughout the year.
Merger - 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 - During 2019, certain holders of Series A preferred units exercised their rights to convert their Series A preferred units into approximately 1.2 million common units as discussed in Note 9.
GP/IDR Exchange - On February 1, 2018, MPC cancelled its IDRs and converted its economic GP Interest in MPLX LP to a non-economic general partner interest in exchange for 275 million newly issued MPLX LP common units. These units had a fair value of $10.4 billion as of the transaction date as recorded on the Consolidated Statements of Equity. As a result of this transaction, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from MPLX. MPC continues to own the non-economic GP Interest in MPLX LP. See Note 7 for more information on the net income per unit calculation.
Class B Conversions - On July 1, 2016 and July 1, 2017, each Class B unit of MPLX LP was converted, in two equal installments, into 1.09 MPLX LP common units and the right to receive $6.20 in cash. Upon the conversion of each tranche of the Class B units, the right of the unitholder, M&R MWE Liberty LLC and certain of its affiliates (“M&R”), to vote as a common unitholder of MPLX was limited to a maximum of five percent of MPLX’s outstanding common units. Additionally, M&R was given the right with respect to such converted units to participate in MPLX’s underwritten offerings of our common units including continuous equity or similar programs in an amount up to 20 percent of the total number of common units
offered by MPLX. M&R may freely transfer such converted units, and M&R has the right to demand that MPLX conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. Following the July 1, 2017 conversion, all MPLX Class B units were eliminated, are no longer outstanding and no longer participate in distributions of cash from MPLX.
ATM Program - On March 13, 2018, MPLX entered into a Third Amended and Restated Distribution Agreement, providing for the at-the-market issuances of common units having an aggregate offering price of up to approximately $1.7 billion, in amounts, at prices and on terms determined by market conditions and other factors at the time of the offerings (such continuous offering program, or at-the-market program is referred to as the “ATM Program”). During the years ended December 31, 2019 and 2018, MPLX issued no common units under the ATM Program. During the year ended December 31, 2017, MPLX issued an aggregate of 13,846,998 common units under the ATM Program generating net proceeds of approximately $473 million. MPLX used the net proceeds from sales under the ATM Program for general business purposes, including repayment or refinancing of debt, and funding for acquisitions, working capital requirements and capital expenditures.
The table below summarizes the changes in the number of units outstanding for the years ended December 31, 2017, 2018, and 2019:
(1)
Changes to the number of general partner units outstanding, other than changes due to contributions made to MPC for the acquisitions of HSM, HST, WHC, MPLXT, the Joint-Interest Acquisition and Refining Logistics and Fuels Distribution, are the result of cash contributions made by the general partner in order to maintain its two percent GP Interest.
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”). The Series B preferred units are pari passu with the Series A preferred units with respect to distribution rights and rights upon liquidation. 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 from the Merger through December 31, 2019 are summarized below and 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 are recorded at fair value as of July 30, 2019.
TexNew Mex Units - Prior to the Merger, MPC held 80,000 Andeavor Logistics TexNew Mex units, representing all outstanding units. At the time of the Merger, each Andeavor Logistics TexNew Mex unit was automatically converted into TexNew Mex units of MPLX with substantially the same rights and obligations as the Andeavor Logistics TexNew Mex units. The TexNew Mex units represent the right to receive quarterly distribution payments in an amount calculated using the distributable cash flow generated by a particular portion of the TexNew Mex pipeline system, in excess of a base amount and adjusted for previously agreed upon stipulations and contingencies. No distributions were payable to TexNew Mex unitholders for distributable cash flow generated during the post-Merger period in 2018. In 2019, distributions of less than $1 million were earned by the TexNew Mex units, which were declared in January of 2020 and paid in February 2020.
Issuance of Additional Securities - The 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. Prior to 2018, when distributions related to the IDRs were made, earnings equal to the amount of those distributions were first allocated to the general partner before the remaining earnings are allocated to the unitholders, based on their respective ownership percentages. The following table presents the allocation of the general partner’s GP Interest in net income attributable to MPLX, for income statement periods occurring prior to the exchange of the GP economic interests:
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. In accordance with the Partnership Agreement, on January 23, 2020, MPLX declared a quarterly cash distribution, based on the results of the fourth quarter of 2019, totaling $715 million, or $0.6875 per common unit. This rate was also received by Series A preferred unitholders. These distributions were paid
on February 14, 2020 to unitholders of record on February 4, 2020. Distributions for the fourth quarter of 2018 were $0.6475 per common unit while distributions for the twelve months ended December 31, 2019 and 2018 were $2.6900 and $2.5300 per common unit, respectively. The $715 million of common unit distributions is net of $12.5 million in quarterly distributions waived by MPC. 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.
Additionally, as a result of the Merger, 600,000 ANDX preferred units were converted into 600,000 Series B preferred units of MPLX. Series B preferred unitholders are entitled to receive, when and if declared by the board, a fixed distribution of $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. MPLX made a cash distribution to holders of the Series B preferred unitholders on February 15, 2020 for 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, 2019, 2018 and 2017. 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.
(1)
Includes distributions of fourth quarter 2017 income declared on general partner common units issued February 1, 2018 in exchange for the economic general partner interest.
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. Due to the waiver mentioned above, 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 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.
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 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, 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. On January 23, 2020, MPLX declared a quarterly cash distribution of $0.6875 per common unit for the fourth quarter of 2019. Holders of the Series A preferred units will receive 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.
On September 20, 2019, certain holders exercised their right to convert a total of 1.2 million Series A preferred units into common units. As a result of the transaction, approximately 29.6 million Series A preferred units remain outstanding as of December 31, 2019.
The changes in the redeemable preferred balance for 2019 and 2018 are summarized below:
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.
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, stores, distributes and markets crude oil, asphalt, refined petroleum products and water. Also includes an inland marine business, terminals, rail facilities, storage caverns and refining logistics.
•
G&P - gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs.
During the second quarter of 2018, our CEO began to evaluate the performance of our segments using Segment Adjusted EBITDA. We have modified our presentation of segment performance metrics to be consistent with this change, including prior periods presented for consistent and comparable presentation. 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 revenues and other income, capital expenditures and investments in unconsolidated affiliates for the years ended December 31, 2019, 2018 and 2017 as well as total assets for our reportable segments as of December 31, 2019 and 2018:
(1)
Within the total segment revenues and other income amounts presented above, third party revenues for the L&S segment were $660 million, $371 million and $160 million for 2019, 2018 and 2017, respectively. Third party revenues for the G&P segment were $3,474 million, $3,198 million and $2,246 million for 2019, 2018 and 2017, respectively.
(2)
See below for the reconciliation from Segment Adjusted EBITDA to “Net income.”
The table below provides a reconciliation between “Net income” and Segment Adjusted EBITDA.
(1)
Depreciation and amortization attributable to L&S was $503 million, $308 million and $163 million for the years ended 2019, 2018 and 2017, respectively. Depreciation and amortization attributable to G&P was $751 million, $559 million and $520 million for 2019, 2018 and 2017, 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.
(1)
The percent calculations exclude revenues attributable to volumes shipped by MPC under joint tariffs with third parties, which are treated as third-party revenue for accounting purposes.
(2)
Operating revenues consist of service revenue, service revenue - product related, rental income and product sales.
MPLX has a concentration of trade receivables due from customers in the same industry: MPC, integrated oil 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.
12. Inventories
Inventories consist of the following:
13. Property, Plant and Equipment
Property, plant and equipment with associated accumulated depreciation is shown below:
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. As a result of the Merger and subsequent changes to our internal organization structure, the number of reporting units was reduced from 12 to 6 in conjunction with our annual impairment test, however, this change in structure did not have an impact on our operating segments. 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. As a result of our change in reporting units, we performed our goodwill impairment assessment prior to the change in reporting units in addition to performing an impairment assessment immediately following the change in our reporting units. Significant assumptions used to estimate the reporting units’ fair value include 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. After performing our evaluations related to the impairment of goodwill, we recorded an impairment of $1,156 million prior to our change in reporting units and an additional impairment of $41 million subsequent to our change in reporting units, both within
the G&P operating segment. The remainder of the reporting units fair values 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. This resulted in goodwill totaling approximately $9.5 billion as of December 31, 2019, with all but one of our six reporting units having goodwill.
The fair value of the reporting units for the interim goodwill impairment analysis described above 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 expected future results and discount rates, which range from 9.0 percent to 10.0 percent. 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 interim goodwill impairment test will prove to be an accurate prediction of the future. The fair value measurements for the individual reporting units’ overall fair values, and the fair values of the goodwill assigned thereto, represent Level 3 measurements.
The changes in carrying amount of goodwill were as follows for the periods presented:
(1)
Acquisitions in 2018 are inclusive of the Mt. Airy Terminal acquisition as well as the Merger while acquisitions in 2019 are inclusive of measurement period adjustments related to the previously mentioned transactions.
Intangible Assets
MPLX’s intangible assets are comprised of customer contracts and relationships. The weighted average amortization period for intangible assets acquired during 2019 was approximately 9 years. Gross intangible assets with accumulated amortization as of December 31, 2019 and 2018 is shown below:
(1)
Amortization expense attributable to the G&P segment for the years ended December 31, 2019 and 2018 was $127 million and $49 million, respectively. Amortization expense attributable to the L&S segment for the year ended December 31, 2019 and 2018 was $31 million and $14 million, respectively.
Estimated future amortization expense related to the intangible assets at December 31, 2019 is as follows:
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, 2019 and 2018 by fair value hierarchy level. MPLX has elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty.
Level 3 instruments include all NGL transactions and embedded derivatives 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 $0.43 to $1.23 and (2) the probability of renewal of 94 percent for the first five-year term and 83 percent for the second five-year 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. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability. Beyond the embedded derivative discussed above, we had no outstanding commodity contracts as of December 31, 2019 or December 31, 2018.
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.
(1)
Gains and losses on commodity derivatives classified as Level 3 are recorded in “Product sales” on the Consolidated Statements of Income. Gains and losses on derivatives embedded in commodity contracts are recorded in “Purchased product costs” and “Cost of revenues” on the Consolidated Statements of Income.
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 long-term 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 approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 16).
The fair value of MPLX’s long-term debt is estimated based on recent market non-binding indicative quotes. The fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash flows and MPLX’s unsecured borrowing rate. The long-term debt and SMR liability fair values are considered Level 3 measurements. The following table summarizes the fair value and carrying value of the long-term debt, excluding finance leases, and SMR liability.
16. Derivative Financial Instruments
As of December 31, 2019, MPLX had no outstanding commodity contracts.
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 2022. The customer has the unilateral option to extend the agreement for two consecutive five-year terms through December 2032. For accounting purposes, the natural gas purchase commitment and term extending options have been aggregated into a single compound embedded derivative. The probability of
the customer exercising its options 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. As of December 31, 2019 and 2018, the estimated fair value of this contract was a liability of $60 million and $61 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, 2019 and 2018, there 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:
(1)
Includes embedded derivatives in commodity contracts as discussed above.
For further information regarding the fair value measurement of derivative instruments, including the effect of master netting arrangements or collateral, see Note 15. See Note 2 for a discussion of derivatives MPLX may use and the reasons for them.
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:
17. Debt
MPLX’s outstanding borrowings at December 31, 2019 and 2018 consisted of the following:
(1)
See Note 22 for lease information.
The following table shows five years of scheduled debt payments, including payments on finance lease obligations:
Credit Agreements
MPLX Credit Agreement
Effective July 30, 2019, in connection with the closing of the Merger, MPLX amended and restated its existing revolving credit facility (the “MPLX Credit Agreement”) to, among other things, increase borrowing capacity to up to $3.5 billion, extend its term from July 2022 to July 2024, increase the letter of credit issuing capacity to $300 million and increase the swingline capacity to $150 million. The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility.
The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $1 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, 2019, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.
During the year ended December 31, 2019, MPLX borrowed $5,310 million under the MPLX Credit Agreement, at a weighted average interest rate of 3.547 percent, and repaid $5,310 million of these borrowings. At December 31, 2019, MPLX had no outstanding borrowings under the new facility and less than $1 million in letters of credit outstanding under this facility, resulting in total availability of $3.5 billion, or almost 100.0 percent of the borrowing capacity.
During the year ended December 31, 2018, MPLX borrowed $1,410 million under the MPLX Credit Agreement, at a weighted average interest rate of 3.464 percent, and repaid $1,915 million of these borrowings. At December 31, 2018, MPLX had no outstanding borrowings and $3 million in letters of credit outstanding under this facility, resulting in total availability of $2.2 billion, or 99.9 percent of the borrowing capacity.
ANDX Credit Facilities
Prior to the Merger, ANDX had revolving credit facilities (the “ANDX credit facilities”) totaling $2.1 billion in borrowing capacity which were set to mature January 29, 2021. The ANDX credit facilities were terminated upon closing of the Merger and repaid with borrowings under the MPLX revolving credit facility. During the year ended December 31, 2019, there were borrowings of $864 million under the ANDX credit facilities, at an average interest rate of 4.129 percent, and repayments of $2.1 billion.
On October 1, 2018, the date on which common control was established, there were outstanding borrowings on the ANDX credit facilities of $1.1 billion. From October 1, 2018 through December 31, 2018, ANDX borrowed $760 million at an average interest rate of 4.061 percent and repaid $635 million, resulting in a balance of $1.2 billion at December 31, 2018.
Term Loan Agreement
On September 26, 2019, MPLX entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1 billion. Borrowings under the Term Loan Agreement bear 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). The proceeds from borrowings under the Term Loan Agreement are to be used to fund the repayment of MPLX’s existing indebtedness and/or for general business purposes. Amounts borrowed under the Term Loan Agreement will be due and payable on September 26, 2021. As of December 31, 2019, MPLX had drawn $1.0 billion on the term loan at an average interest rate of 2.561 percent.
The Term Loan Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider to be customary for an agreement of this type and are substantially similar to those contained in the MPLX Credit Agreement, including a covenant that requires MPLX’s ratio of Consolidated Total Debt to Consolidated EBITDA (as both terms are defined in the Term Loan Agreement) for the four prior fiscal quarters not to exceed 5.0 to 1.0 as of the last day of each fiscal quarter (or during the six-month period following certain acquisitions, 5.5 to 1.0). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period.
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 are 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 is payable quarterly in March, June, September and December, commencing on December 9, 2019. The interest rate applicable to the floating rate senior notes due September 2021 is LIBOR plus 0.9 percent per annum. The interest rate applicable to the floating rate senior notes due September 2022 is LIBOR plus 1.1 percent per annum.
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.
In connection with the Merger, MPLX assumed ANDX’s outstanding senior notes, which had an aggregate principal amount of $3.75 billion, interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion unsecured senior notes (the “Exchange Notes”) issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX. Of this, $500 million aggregate principal amount is related to ANDX 5.5 percent senior notes due 2019. The aggregate principal amount of $500 million and accrued interest of $13.75 million was paid on October 15, 2019 using net proceeds from the Floating Rate Senior Notes and borrowings under the Term Loan Agreement discussed above and includes interest through the payoff date.
The Exchange Notes consist of $266 million in aggregate principal amount of 6.25 percent senior notes due October 2022, $486 million in aggregate principal amount of 3.5 percent senior notes due December 2022, $381 million in aggregate principal amount of 6.375 percent senior notes due May 2024, $708 million in aggregate principal amount of 5.25 percent senior notes due January 2025, $732 million in aggregate principal amount of 4.25 percent senior notes due December 2027 and $487 million in aggregate principal amount of 5.2 percent senior notes due December 2047. Interest on each series of Exchange Notes is payable semi-annually in arrears according to the table above.
On December 10, 2018, MPLX redeemed all of the $750 million aggregate principal amount of 5.5 percent senior notes due February 15, 2023, $40 million of which was issued by the MarkWest subsidiary. These notes were redeemed at 101.833 percent of the aggregate principal amount, which resulted in a payment of $14 million related to the note premium and the immediate recognition of $46 million of unamortized debt issuance costs.
On November 15, 2018, MPLX issued $2.25 billion aggregate principal amount of senior notes in a public offering, consisting of $750 million aggregate principal amount of 4.8 percent senior notes due February
2029 and $1.5 billion aggregate principal amount of 5.5 percent senior notes due February 2049 (collectively, the “November 2018 New Senior Notes”). The November 2018 New Senior Notes were offered at a price to the public of 99.432 percent and 98.031 percent of par, respectively. The net proceeds were used to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement and to redeem the $750 million aggregate principal amount of 5.5 percent senior notes due February 2023, as well as for general business purposes. Interest on each series of notes in the November 2018 New Senior Notes is payable semi-annually in arrears, commencing on February 15, 2019.
On February 8, 2018, MPLX issued $5.5 billion aggregate principal amount of senior notes in a public offering, consisting of $500 million aggregate principal amount of 3.375 percent senior notes due March 2023, $1.25 billion aggregate principal amount of 4.0 percent senior notes due March 2028, $1.75 billion aggregate principal amount of 4.5 percent senior notes due April 2038, $1.5 billion aggregate principal amount of 4.7 percent senior notes due April 2048, and $500 million aggregate principal amount of 4.9 percent senior notes due April 2058 (collectively, the “February 2018 New Senior Notes”). The February 2018 New Senior Notes were offered at a price to the public of 99.931 percent, 99.551 percent, 98.811 percent, 99.348 percent, and 99.289 percent of par, respectively. Also on February 8, 2018, $4.1 billion of the net proceeds from the offering were used to repay the 364-day term loan facility, which was drawn on February 1, 2018 to fund the cash portion of the dropdown consideration for Refining Logistics and Fuels Distribution. The remaining net proceeds were used to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement, as well as for general business purposes. Interest on each series of notes due in 2023 and 2028 is payable semi-annually in arrears, commencing on September 15, 2018. Interest on each series of notes due in 2038, 2048 and 2058 is payable semi-annually in arrears, commencing on October 15, 2018.
SMR Transaction
On September 1, 2009, MarkWest completed the sale of the SMR (the “SMR Transaction”). At that time, MarkWest had begun constructing the SMR at its Javelina gas processing and fractionation complex in Corpus Christi, Texas. Under the terms of the agreement, MarkWest received proceeds of $73 million and the purchaser completed the construction of the SMR. MarkWest and the purchaser also executed a related product supply agreement under which MPLX will receive the entire product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations in March 2010. MarkWest was deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP. MPLX imputes interest on the SMR liability at 6.39 percent annually, its incremental borrowing rate at the time of the purchase accounting valuation. Each processing fee payment has multiple elements: reduction of principal of the SMR liability, interest expense associated with the SMR liability and facility expense related to the operation of the SMR. As part of purchase accounting, the SMR Transaction has been recorded at fair value. As of December 31, 2019 and 2018, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets:
18. Revenue
Disaggregation of Revenue
The following table represents a disaggregation of revenue for each reportable segment for the years ended December 31, 2019 and 2018:
(1)
G&P “Product sales” for the year ended December 31, 2018 was adjusted in the table above by $5 million related to derivative gains and mark-to-market adjustments. There were no adjustments for the year ended December 31, 2019.
(2)
Non-ASC 606 Revenue includes rental income, income from equity method investments, derivative gains and losses, mark-to-market adjustments, and other income.
Contract Balances
Contract assets typically relate to 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 generally classified as current and included in “Other current 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 table below reflects the changes in our contract balances for the years ended December 31, 2019 and 2018:
(1)
Balance represents ASC 606 portion of each respective line item.
(2)
No significant revenue was recognized related to past performance obligations for the years ended December 31, 2019 and 2018.
(3)
Includes opening balances related to the Merger.
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, 2019, the amounts allocated to contract assets and contract liabilities on the Consolidated Balance Sheets are $220 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 24 years. Further, MPLX does not disclose variable consideration due to volume variability in the table below.
(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 are included in “Rental income” and are excluded from this table.
(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.
19. Supplemental Cash Flow Information
(1) The restricted cash balance is included within “Other current assets” on the Consolidated Balance Sheets.
(1)
Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings.
(2)
For 2017, includes limited and general partner units issued to MPC as consideration in the acquisitions of the joint-interests, HST, WHC and MPLXT. For 2018, includes limited and general partner units issued to MPC as consideration in the acquisition of Refining Logistics and Fuels Distribution. For 2019, includes limited partner units issued to MPC and public unitholders as consideration in the Merger. See Note 4.
At December 31, 2017, “Payables - related parties” per the Consolidated Balance Sheets included an $11 million payable to MPC for distributions of cash received from Joint-Interest Acquisition entities that did not affect cash.
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:
20. Accumulated Other Comprehensive Loss
MPLX records an accumulated other comprehensive loss on the Consolidated Balance Sheets relating to pension and other post-retirement benefits provided by LOOP and Explorer to their employees. MPLX is not a sponsor of these benefit plans. As a transfer between entities under common control, MPLX recorded the Joint-Interest Acquisition from MPC on the Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss. MPLX’s assumption of the accumulated other comprehensive loss balance had no effect on MPLX’s comprehensive income during the period as the balance was accumulated while under the ownership of MPC.
The following table shows the changes in “Accumulated other comprehensive loss” by component during the period December 31, 2017 through December 31, 2019:
(1)
These components of “Accumulated other comprehensive loss” are included in the computation of net periodic benefit cost by LOOP and Explorer and are therefore included on the Consolidated Statements of Income under the caption “Income/(loss) from equity method investments.”
(2)
Components of other comprehensive loss - remeasurements relate to actuarial gains and losses as well as amortization of prior service costs. MPLX records an adjustment to “Comprehensive income” in accordance with its ownership interest in LOOP and Explorer.
21. Equity-Based Compensation
Description of the Plan
Effective March 15, 2018, the MPLX LP 2012 Incentive Compensation Plan (“MPLX 2012 Plan”) was replaced by the MPLX LP 2018 Incentive Compensation Plan (“MPLX 2018 Plan”). The MPLX 2018 Plan will continue in effect until February 28, 2028, unless terminated earlier. Subject to customary anti-dilution adjustments, the MPLX 2018 Plan allows for no more than 16 million common units representing limited partnership interests in MPLX to be delivered under the plan. The MPLX LP 2012 Plan allowed for no more than 2.75 million MPLX LP common limited partner units to be delivered.
Consistent with the MPLX 2012 Plan, the MPLX 2018 Plan authorizes the MPLX GP board of directors (the “Board”) to grant unit options, unit appreciation rights, restricted units and phantom units, distribution equivalent rights, unit awards, profits interest units, performance units and other unit-based awards to the employees, officers and directors of the General Partner, MPLX, or any of their affiliates, including MPC. Common units delivered pursuant to an award granted under the MPLX 2018 Plan may be newly issued common units or acquired in the open market or from any other person, including an affiliate of MPLX, as determined by the Board.
Unit-based Awards under the Plan
MPLX expenses all unit-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures.
Phantom Units - MPLX has granted phantom units under the MPLX 2018 Plan and the MPLX 2012 Plan to non-employee directors of MPLX LP’s general partner and of MPC. Awards to non-employee directors are accounted for as non-employee awards. Phantom units granted to non-employee directors vest immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Prior to issuance, non-employee directors do not have the right to
vote such units and cash distribution equivalents accrue in the form of additional phantom units and will be issued when the director departs from the board of directors.
MPLX has granted phantom units under the MPLX 2018 Plan and the MPLX 2012 Plan to certain officers and non-officers of MPLX, MPLX’s general partner and MPC who make significant contributions to our business. These grants are accounted for as employee awards. In general, these phantom units will vest over a requisite service period of up to three years. Prior to vesting, these phantom unit recipients will not have the right to vote such units and cash distributions declared will be accrued and paid upon vesting. The accrued distributions at December 31, 2019 and 2018 were $6 million and $4 million, respectively.
The fair values of phantom units are based on the fair value of MPLX common units on the grant date.
Performance Units - MPLX has granted performance units under the MPLX 2018 Plan and the MPLX 2012 Plan to certain officers of the general partner and certain eligible MPC officers who make significant contributions to our business. Performance units are designed to pay out 75 percent in cash and 25 percent in MPLX common units. The 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.
The performance units granted in 2017 are hybrid awards having a three-year performance period of January 1, 2017 through December 31, 2019. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX’s DCF during the last twelve months of the performance period, and a market condition based on MPLX’s total unitholder return over the entire three-year performance period.
During the first quarter of 2018, a performance award was granted; however, a grant date could not be established based on the nature of the award terms. Given that a grant date cannot be established, no expense or units have been recorded. When a grant date is established, the fair value of the award will be recognized over the remaining service period.
The performance units granted in 2019 are hybrid awards having a three-year performance period of January 1, 2019 through December 31, 2021. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX’s DCF during the performance period and a market condition based on MPLX’s total unitholder return over the performance period. The market condition was valued using a Monte Carlo valuation, resulting in a grant date fair value of $0.68 per unit for the 2019 equity-classified performance units. Grant date fair value of the performance condition is based on potential payouts per unit of up to $2.00 per unit. Compensation cost associated with the performance condition is based on the grant date fair value of the payout deemed most probable to occur and is adjusted as the expectation for payout changes.
Outstanding Phantom Unit Awards
The following is a summary of phantom unit award activity of MPLX common units in 2019:
(1)
Represents a subset of phantom units held by our non-employee directors and certain of our officers and non-officer employees that are generally non-forfeitable and that would be paid out as common units upon the holder’s separation from service.
The following is a summary of the values related to phantom units:
As of December 31, 2019, unrecognized compensation cost related to phantom unit awards was $9 million, which is expected to be recognized over a weighted average period of 1.3 years.
Outstanding Performance Unit Awards
The following table presents a summary of the 2019 activity for performance unit awards to be settled in MPLX common units:
The number of common units that would be issued upon target vesting, using the closing price of our common units on December 31, 2019 would be 84,735 common units.
As of December 31, 2019, unrecognized compensation cost related to equity-classified performance unit awards was $1 million which is expected to be recognized over a weighted average period of 2.0 years.
Performance units paying out in MPLX common units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of the weighted average inputs used for these assumptions:
The assumption for expected volatility of our unit price reflects the historical volatility of MPLX common units. The look-back period reflects the remaining performance period at the grant date. The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant. No grant date fair value has been calculated for performance units granted in 2018, since due to the award terms, a grant date has not yet been established.
Total Unit-Based Compensation Expense
Total unit-based compensation expense for awards settling in MPLX common units was $22 million in 2019, $24 million in 2018 and $18 million in 2017.
MPC’s Stock-based Compensation
Stock-based compensation expenses charged to MPLX under our employee services agreement with MPC were $10 million, $8 million and $2 million for 2019, 2018 and 2017, respectively.
22. 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 one to 59 years. Some long-term leases include renewal options ranging from one 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.
Under ASC 840, operating lease costs were $89 million in 2018 and $64 million in 2017. Under ASC 842, the components of lease cost were as follows:
Supplemental balance sheet data related to leases were as follows:
As of December 31, 2019, 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:
Future minimum commitments as of December 31, 2018, for capital lease obligations and for operating lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:
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 1 year to 11 years with renewal options ranging from 1 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 2023 and 2033, 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. Lessor agreements are currently deemed operating, as we elected the practical expedient to carry forward historical classification conclusions. If and when a modification of an existing agreement occurs and the agreement is required to be assessed under ASC 842, MPLX assesses the amended agreement and makes a determination as to whether a reclassification of the lease is required.
During the year ended December 31, 2019, there was a modification to MPLX terminal agreements with MPC. Based on the modification, certain terminals within the MPLX terminal agreement were reclassified from operating leases to sales-type leases. As a result, 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. When determining the net investment in the lease, certain variable payments were excluded from the total contract consideration, primarily related to fees for which there are no minimum volume commitments. The difference between the net book value of the underlying assets and the net investment in the lease has been recorded through equity given that the dropdown of MPLXT was a common control transaction. During the year, MPLX derecognized approximately $29 million of property, plant and equipment, derecognized approximately $3 million of existing deferred rent receivable, recorded a lease receivable of approximately $47 million, recorded an unguaranteed residual asset of approximately $6 million and equity of $21 million.
Under ASC 840, MPLX’s revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $1,032 million in 2018 and $601 million in 2017. Lease revenues included on the Consolidated Statements of Income during 2019 were as follows:
(1)
These amounts are presented net of executory costs.
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of December 31, 2019:
The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of December 31, 2018:
The following is a schedule of minimum future revenue on the sales-type leases with MPC as of December 31, 2019:
The following schedule summarizes MPLX’s investment in assets held for operating lease by major classes as of December 31, 2019 and 2018:
23. 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 an accrued liability, MPLX is unable to estimate a range of possible losses for the reasons discussed in more detail below. 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, 2019 and 2018, accrued liabilities for remediation totaled $19 million and $20 million, respectively. However, it is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, which may be imposed. At December 31, 2019 and 2018, there were no balances with MPC for indemnification of environmental costs.
MarkWest Liberty Midstream, Ohio Fractionation and MarkWest Utica EMG, together with other MarkWest affiliates, agreed to pay a penalty of approximately $0.9 million, undertake certain monitoring and emission reduction projects at certain facilities with an estimated cost of approximately $3.3 million, and implement certain process enhancements for its and its affiliates’ leak detection and repair programs at
its gas processing and fractionation sites. On November 1, 2018, MPLX and 11 of its subsidiaries entered into a Consent Decree with the EPA, the State of Oklahoma, the Pennsylvania Department of Environmental Protection and the State of West Virginia resolving these issues. The Consent Decree was approved by the court on January 8, 2019 and the penalty has been paid.
MPLX is involved in environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on 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.
Other Lawsuits - MPLX, MarkWest, MarkWest Liberty Midstream, MarkWest Liberty Bluestone, L.L.C., Ohio Fractionation and MarkWest Utica EMG (collectively, the “MPLX Parties”) were parties to various lawsuits with Bilfinger Westcon, Inc. (“Westcon”) that were instituted in 2016 and 2017 in the Court of Common Pleas in Butler County, Pennsylvania, the Circuit Court in Wetzel County, West Virginia, and the Court of Common Pleas in Harrison County, Ohio. The lawsuits related to disputes regarding construction work performed by Westcon at the Bluestone, Mobley and Cadiz processing complexes in Pennsylvania, West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. As previously disclosed in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2019, in July 2019, Westcon and the MPLX Parties reached an agreement to resolve the disputes among those parties relating to the Bluestone processing complex in Pennsylvania. In the quarter ended December 31, 2019, Westcon and the MPLX Parties reached agreements to resolve the remaining disputes among those parties relating to the Mobley and Cadiz processing complexes in West Virginia and Ohio, respectively, and the Hopedale fractionation complex in Ohio. The settlements will not have a material adverse effect on MPLX’s consolidated financial position, results of operations or cash flows.
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. 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.
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 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.
In connection with our approximate 9 percent indirect interest in a joint venture that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system, we have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, have 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 Bakken Pipeline system. At December 31, 2019, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement was approximately $230 million.
Contractual Commitments and Contingencies - At December 31, 2019, MPLX’s contractual commitments to acquire property, plant and equipment totaled $753 million. These commitments were primarily related to G&P plant expansion, terminal, pipeline and refining logistics projects. 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 the processing arrangements if there are significant delays that are not due to force majeure. As of December 31, 2019, 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 transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which range from four to 20 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, 2019 are as follows:
SMR Transaction - On September 1, 2009, MarkWest entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for the entire product processed by the SMR. See Note 17 for additional discussion. The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows:
Select Quarterly Financial Data (Unaudited)
(1)
As discussed in Note 1, MPLX’s acquisition of ANDX is considered a transfer between entities under common control due to MPC’s prior relationship with ANDX. 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 tables above include the historical results of ANDX beginning October 1, 2018. Amounts shown for the fourth quarter of 2018 as well as the first and second quarters of 2019 are different than amounts previously reported for Total revenues and other income, Income from operations and Net income as a results of this retrospective adjustment for ANDX. Total revenues and other income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $1,715 million, $1,646 million and $1,629 million, respectively. Income from operations originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $666 million, $678 million and $659 million, respectively. Net income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $439 million, $509 million and $488 million, respectively.
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
None
Item 9A.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
MPLX’s management, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934 Act, as amended, as of December 31, 2019. Based on this evaluation, MPLX’s management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of December 31, 2019, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the Securities Exchange Act of 1934 Act, as amended, is recorded, processed, summarized, and reported within the time periods specified in the SEC’s rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.
Internal Control Over Financial Reporting and Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2019, 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. See Item 8. Financial Statements and Supplementary Data - Management’s Report on Internal Control over Financial Reporting.
Limitations on Controls
Management has designed our disclosure controls and procedures and internal control over financial reporting to provide reasonable assurance of achieving their objectives as specified above. Management does not expect, however, that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that management has detected all control issues and instances of fraud, if any, within MPLX.
Item 9B.
Item 9B. Other Information
None
Part III
Item 10.
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.
DIRECTORS AND EXECUTIVE OFFICERS OF MPLX GP LLC
The following table shows information for our directors, and executive and corporate officers as of January 31, 2020.
*
Corporate officer
Mr. Heminger has served as Chairman of the Board since June 2012 and as Chief Executive Officer from June 2012 through October 2019. He has served as MPC’s Chairman of the Board since April 2016, as its Chief Executive Officer since June 2011, and as its President from 2011 to 2017. Mr. Heminger began his career with Marathon in 1975 and has served in roles in finance and administration, auditing, marketing and commercial, and business development, including as President of Marathon Pipe Line Company; Manager, Business Development and Joint Interest of Marathon Oil Company; and Vice President and Senior Vice President, Business Development, Marathon Ashland Petroleum LLC. In 2001, he was named Executive Vice President, Supply, Transportation and Marketing, and was appointed President of Marathon Petroleum Company LLC and Executive Vice President-Downstream of Marathon Oil Corporation later that year. Mr. Heminger has announced his plans to retire from the Board and from MPC effective April 29, 2020.
Mr. Heminger serves on the boards of directors and executive committees of the American Petroleum Institute (API) and the American Fuel & Petrochemicals Manufacturers (AFPM), and is a member of the Oxford Institute for Energy Studies. He is Chair of The Ohio State University Board of Trustees and past Chair of the Tiffin University Board of Trustees. Mr. Heminger holds a bachelor’s degree in accounting from Tiffin University and a master’s degree in business administration from the University of Dayton, and he is a graduate of the Wharton School Advanced Management Program at the University of Pennsylvania.
Qualifications: Mr. Heminger brings to the Board energy industry expertise, extensive knowledge of all aspects of our business and a breadth of transactional experience. As our former Chief Executive Officer, he leverages that expertise in advising on our strategic direction and apprising the Board on issues of significance to our industry and to us.
Other Public Company Directorships: Marathon Petroleum Corporation (since 2011); Tesoro Logistics GP, LLC (2018-2019); Fifth Third Bancorp (since 2006); PPG Industries, Inc. (since 2017)
Mr. Hennigan was appointed Chief Executive Officer effective November 2019 and has served as President since June 2017. He has also served on the Board of Directors since June 2017. 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 more than 38 years of industry experience, including as the president and chief executive officer of a successful growth-oriented master limited partnership.
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); Sunoco Partners LLC (2010-2017); Niska Gas Storage Partners LLC (2014-2016)
Ms. Beall was appointed Executive Vice President and Chief Financial Officer effective 2016, and was elected a member of the Board in January 2014. Ms. Beall began her career with Marathon in 1978 as an auditor. She then served as General Manager, Treasury Services, at USX Corporation; Vice President and Treasurer at NationsRent, Inc. and OHM Corporation; and as a member of the boards of directors of System One Services, Inc. and Boyle Engineering. Ms. Beall rejoined Marathon in 2002, serving in areas of increasing responsibility, including as Director, Corporate Affairs; Organizational Vice President, Business Development - Downstream; Vice President of Global Procurement, Marathon Oil Company; and Vice President of Products, Supply & Optimization. She served as MPC’s Vice President, Investor Relations and Government & Public Affairs from 2011 to 2014, when she was named President of MPLX GP. Ms. Beall was also named Executive Vice President, Corporate Planning and Strategy of MPLX GP in 2016. She serves on the University of Findlay Board of Trustees and is a member of the Ohio Society of CPAs. Ms. Beall holds a bachelor’s degree in accounting from the University of Findlay and a master’s degree in business administration from Bowling Green State University, and she has attended the Oxford Institute for Energy Studies. She is licensed as a certified public accountant in Ohio.
Qualifications: Ms. Beall brings to the Board extensive energy industry experience, specifically in the areas of finance and accounting, business development, risk management, procurement, investor relations and government affairs. In addition, her service as a senior executive in the environmental remediation and industrial product rental sectors equips her to contribute valuable insight into our business and operations.
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); National Retail Properties, Inc. (since 2016)
Mr. Beatty was elected a member of the Board in December 2015, at the time of the MarkWest Merger. Mr. Beatty served on the board of directors of MarkWest’s general partner from 2008 to 2015, and prior to that, on the board of directors of MarkWest Hydrocarbon. Mr. Beatty is a former Chairman of the law firm of Beatty & Wozniak, P.C., with a practice focused exclusively on energy, including oil and gas exploration,
regulatory affairs, public lands, litigation and title. He began his career in the energy industry as in-house counsel for Colorado Interstate Gas Company, and ultimately became Executive Vice President, General Counsel and Director of The Coastal Corporation. He also served as Chief of Staff to Governor Roy Romer of Colorado. Mr. Beatty holds an undergraduate degree from the University of California, Berkeley and a juris doctor degree from Harvard Law School. He also serves on the board of directors of the Cystic Fibrosis Foundation.
Qualifications: Mr. Beatty brings to the Board extensive experience in the oil and gas industry, including significant experience in energy policy and energy regulation gained through his experience as a director, officer and legal counsel of various energy companies, as well as extensive historical knowledge of MarkWest.
Other Public Company Directorships: Denbury Resources Inc. (2007-2015); MarkWest Energy GP, L.L.C. (2008-2015)
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. He also serves on the board of directors of TRC Companies, L.L.C. 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: Range Resources Corporation (2014-2019); Questar Corporation (2013-2016)
Mr. Peiffer was elected a member of the Board in June 2012, and served as our President from 2012 until his retirement in January 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 the Fifth Third Bank (Northwestern Ohio). Mr. Peiffer is also a member of the boards of trustees of the Blanchard Valley Health System and the Findlay-Hancock County Community Foundation and serves on the Blanchard Valley Port Authority Board. 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 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 realizing several joint ventures and corporate reorganizations and implementing new information technology solutions.
Other Public Company Directorships: 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 serves on the CONSOL Coal Resources GP LLC Board of Directors and 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: CONSOL Coal Resources GP LLC (since 2017)
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: Tortoise Acquisition Corp (since 2019); Tesoro Logistics GP, LLC (2018-2019); Marathon Petroleum Corporation (2015-2018); MarkWest Energy GP, L.L.C. (2003-2015)
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 August 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, 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 previously served on the board of directors of MarkWest, which we acquired in 2015. He has 35 years of experience in the upstream and midstream gas businesses.
Other Public Company Directorships: Marathon Petroleum Corporation (since 2017); U.S. Silica Holdings, Inc. (since 2013); Spartan Energy Acquisition Corporation (since 2018); Access Midstream Partners GP, L.L.C. (2012-2015); MarkWest Energy GP, L.L.C. (2015); SandRidge Energy, Inc. (2015-2016); Williams Partners GP LLC (2015)
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 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, Mr. Surma 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, Mr. Surma 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 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: Marathon Petroleum Corporation (since 2011); Concho Resources Inc. (since 2014); Ingersoll-Rand plc (since 2013); Public Service Enterprise Group Inc. (since 2019); United States Steel Corporation (2001-2013)
Mr. Templin was elected a member of the Board in June 2012. He was appointed Executive Vice President and Chief Financial Officer of MPC effective July 2019. Prior to this appointment, he served as President, Refining, Marketing and Supply of MPC beginning in October 2018, President of MPC beginning in 2017, President of MPLX GP and Executive Vice President of MPC beginning in 2016, Executive Vice President, Supply, Transportation and Marketing of MPC beginning in 2015, Vice President and Chief Financial Officer of MPLX GP beginning in 2012, and Senior Vice President and Chief Financial Officer of MPC beginning in 2011. Prior to joining MPC, Mr. Templin was a managing partner of the audit practice of PricewaterhouseCoopers LLP with more than 25 years of providing auditing and advisory services to a wide variety of private, public and multinational companies. He is a member of the Grove City College Board of Trustees and past Chairman of the Downstream Committee of API. Mr. Templin is a graduate of Grove City College, a certified public accountant, a member of the American Institute of Certified Public Accountants and has attended the Oxford Institute for Energy Studies.
Qualifications: Mr. Templin brings to the Board direct insight into all aspects of our business, from an operational and commercial perspective, and in the areas of accounting, audit and financial management. His long and successful background in public accounting for energy sector clients affords him insight into public company financial reporting requirements and related matters.
Other Public Company Directorships: Tesoro Logistics GP, LLC (2018-2019); Calgon Carbon Corporation (2013-2018)
Mr. Floerke was appointed Executive Vice President, Gathering and Processing effective 2018. Prior to this appointment, he served as 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 December 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. Swearingen was appointed Executive Vice President, Logistics and Storage effective July 2017. Prior to this appointment, he served as Vice President, Crude Oil and Refined Products Pipelines and Chief Operating Officer, Pipeline Operations and as MPC’s Senior Vice President, Transportation and Logistics beginning in March 2015. He previously served in various leadership positions with MPC and its affiliates, including as MPC’s Vice President, Health, Environment, Safety and Security beginning in 2011 and President of Marathon Pipe Line LLC beginning in 2009.
Ms. Gagle was appointed General Counsel effective October 2017, and General Counsel of MPC effective March 2016. Prior to this appointment, she served as MPC’s Assistant General Counsel, Litigation and Human Resources beginning in April 2011, Senior Group Counsel, Downstream Operations beginning in 2010, and Group Counsel, Litigation beginning in 2003.
Mr. Brooks was appointed Senior Vice President effective February 2018, and MPC’s Executive Vice President, Refining effective October 2018. Prior to this appointment, he served as MPC’s Senior Vice President, Refining beginning in March 2016, General Manager of MPC’s Galveston Bay, Texas refinery beginning in February 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.
Mr. Hessling was appointed Senior Vice President, and MPC’s Senior Vice President, Crude Oil Supply and Logistics effective October 2018. Prior to this appointment, he served as MPC’s Manager, Crude Oil & Natural Gas Supply and Trading beginning in September 2014, and Crude Oil Logistics & Analysis Manager beginning in July 2011.
Mr. Partee was appointed Senior Vice President, and MPC’s Senior Vice President, Marketing effective October 2018. Prior to this appointment, he 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 September 2014, and Vice President, Business Development and Franchise at Speedway beginning in November 2012.
Mr. Whikehart was appointed Senior Vice President, and MPC’s Senior Vice President, Light Products, Supply and Logistics effective October 2018. Prior to this appointment, he served as MPC’s Vice President, Environment, Safety and Corporate Affairs beginning in February 2016, Vice President, Corporate Planning, Government & Public Affairs beginning in January 2016, and Director, Product Supply and Optimization beginning in March 2011.
Mr. Aydt was appointed Vice President, Business Development effective November 2018. Prior to this appointment, he served as 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 Detroit Heavy Oil Upgrade Project beginning in 2008.
Ms. Benson was appointed Vice President, Chief Compliance Officer and Corporate Secretary for MPC and us effective March 2016, and Chief Securities and Governance Officer of MPC and us effective June 2018. Prior to her 2016 appointment, Ms. Benson was MPC’s Assistant General Counsel, Corporate and Finance beginning in April 2012, and Group Counsel, Corporate and Finance beginning in 2011.
Mr. Gilgen was appointed Vice President and Treasurer effective February 2017. Prior to that, he was our Assistant Treasurer beginning in 2012 and the Assistant Treasurer of MPC beginning in 2011.
Mr. Hagedorn was appointed Vice President and Controller effective October 2017. Prior to this appointment, he was Vice President and Controller at CONSOL Energy Inc., a Pennsylvania-based coal producer and exporter, beginning in 2015, Assistant Controller beginning in 2014 and Director, Financial Accounting beginning in 2012. He was Chief Accounting Officer for CONE Midstream Partners LP, a publicly traded master limited partnership with gathering assets in the Appalachian Basin, from 2014 to 2015. Previously, Mr. Hagedorn served in positions of increasing responsibility with PricewaterhouseCoopers LLP beginning in 1998.
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 September 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 that, he was Vice President of Operations for Marathon Pipe Line LLC beginning in 2011.
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 and director qualifications, director compensation and director retirement and resignation.
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 would post on our website any amendments to, or waivers from, either of these codes requiring disclosure under applicable rules within four business days following any such 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
The Board currently consists of eleven 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. Beatty, 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.
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. Heminger 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.
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. Heminger 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), Beatty, 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 Mr. Peiffer qualifies as an “audit committee financial expert,” as defined by SEC rules, based on the attributes, education and experience further described in his 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 2019 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, 2019, for filing with the SEC.
Garry L. Peiffer, Chair
Michael L. Beatty
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.
Our Conflicts Committee is comprised of Messrs. Helms (Chair), Beatty 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: Attn: Corporate Secretary, MPLX GP LLC, 200 East Hardin Street, Findlay, OH 45840.
Email:
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Independent Directors (individually or as a group): non-managedirectors@mplx.com
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Audit Committee Chair: auditchair@mplx.com
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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.
Item 11.
Item 11. Executive Compensation
EXECUTIVE COMPENSATION DISCUSSION AND ANALYSIS
This Executive Compensation Discussion and Analysis (“CD&A”) provides an overview of our compensation philosophy and objectives and explains how and why 2019 compensation decisions were made for our named executive officers (our “NEOs”). We recommend that 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 2019 included our Chairman and former Chief Executive Officer (“CEO”), current CEO, Chief Financial Officer, and three other most highly compensated executive officers serving at the end of 2019. Our NEOs for 2019 were:
Mr. Heminger has served as our Chairman since June 2012 and as CEO from June 2012 through October 31, 2019. Mr. Hennigan was appointed President and CEO effective November 1, 2019, having previously served as President since June 2017.
COMPENSATION DECISIONS AND 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 these services, including services provided by our NEOs, which totaled approximately $10.3 million for 2019. The only direct compensation we provide our NEOs is in the form of long-term incentive awards of our equity, which are shown in the “2019 Grants of Plan-Based Awards” table and accompanying narrative below.
Compensation Decisions
We have adopted 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 this 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 Allocation
Mr. Heminger, our Chairman, is also CEO and Chairman of MPC, and is generally compensated by MPC for the services he provides to MPC and its affiliates, including us. Mr. Heminger devotes less than a majority of his total business time to us, and we reimburse MPC a fixed amount under our omnibus agreement in return for his services to us. We disclose in this CD&A the amount we reimburse MPC for Mr. Heminger’s services, as well as the long-term incentive awards we have granted him. Together, these
represent all of the material elements of Mr. Heminger’s compensation attributable to the services he provides to our business.
As Ms. Beall and Messrs. Hennigan and Floerke devoted most of their total business time to us in 2019, this CD&A discloses all components of their compensation. This CD&A discloses all components of Mr. Swearingen’s compensation, with the non-equity elements generally prorated at 75% to reflect the portion of his time allocated to us for 2019 under our omnibus agreement, and all components of Ms. Gagle’s compensation, with the non-equity elements generally prorated at 50% to reflect the portion of her time allocated to us for 2019 under our omnibus agreement.
Compensation Consultant
Our Board does not have a standing compensation committee and has not hired its own compensation consultant. MPC’s Compensation Committee has engaged Pay Governance, LLC to provide compensation consulting services and comparative compensation information. This information is typically shared with our Board for use in making certain compensation decisions for our NEOs.
EXECUTIVE COMPENSATION PROGRAM
Base Salary
MPC pays our NEOs a base salary for their services to MPC and its affiliates, including us. In setting base salary, MPC’s Compensation Committee evaluates peer group and other market data, each individual’s experience, contribution and demonstrated performance, MPC’s current and future succession needs, business results and external competitiveness. Taking these matters into consideration, MPC’s Compensation Committee made the following adjustments to our NEOs’ base salaries for 2019:
The MPC Compensation Committee’s decisions to increase Mr. Hennigan’s and Ms. Gagle’s base salaries in particular were based on each NEO’s continued strong performance and the MPC Compensation Committee’s determination to bring each NEO closer to the market median for his or her position. Mr. Hennigan’s base salary was further increased to $1,050,000 (a 10.5% increase) effective November 1, 2019, in recognition of the additional responsibilities he assumed upon his appointment as CEO of MPLX effective on that date. The decisions to increase the base salaries of Ms. Beall, Mr. Swearingen and Mr. Floerke reflect annual merit program increases to maintain market competitiveness.
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including base salary, of Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table and in the “2019 Summary Compensation Table” below at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under our omnibus agreement.
As noted above in “Compensation Decisions and Allocation,” we reimburse MPC a fixed amount in return for Mr. Heminger's services to us. For 2019, this amount was $1,490,000, which is reflected under “Salary” in the “2019 Summary Compensation Table” below.
Annual Cash Bonus Program
Our NEOs were eligible to participate in MPC’s 2019 Annual Cash Bonus (“ACB”) program, which MPC’s Compensation Committee approved in February 2019, as part of their compensation for the services they provide to MPC and its affiliates, including us. MPC determines awards to our NEOs under the ACB
program without input from our Board or us. Under our omnibus agreement, no portion of any bonus paid to our NEOs under the ACB is charged back to us. Awards under the ACB program for our NEOs are calculated as follows:
Year-End Base Salary
×
Bonus Target
×
Performance
=
Final Award
Bonus Target is a percentage of each NEO’s base salary. MPC’s Compensation Committee generally approves target bonus opportunities for our NEOs based on analysis of market-competitive data for MPC’s compensation peer 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 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, as well as other factors MPC’s Compensation Committee deems relevant in its discretion, including each NEO’s organizational and individual performance.
Payout results may be above or below target based on actual company and individual performance and are capped at 200% of each NEO’s target award.
There is no guaranteed minimum ACB payout.
2019 MPC Company Metrics and Performance
MPC's Compensation Committee believes it is important for the ACB program to emphasize pre-established financial and operational (including environmental and safety) performance measures, and has determined to collectively weight these measures at 70%. The following table provides the goals for each metric, target weighting and MPC’s performance achieved in 2019 ($ in millions):
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.
Synergy Capture tracks annualized ongoing enhanced revenue or margin, cost savings and avoided planned capital outlays realized in connection with MPC’s acquisition of Andeavor.
Distributable Cash Flow at MPLX 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. This metric also includes distributable cash flow at ANDX, which we acquired by merger effective July 30, 2019.
EBITDA 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.
Mechanical Availability measures the availability of the processing equipment in MPC’s refineries and the critical equipment in MPC’s midstream assets.
Marathon Safety Performance Index measures MPC’s success and commitment to employee safety. Goals are set annually at best-in-class industry performance, focusing on continual improvement and include common industry metrics.
Process Safety Events Rate measures MPC’s ability to identify, understand and control certain process hazards.
Designated Environmental Incidents measures certain internal environmental performance metrics.
Quality Incidents measures the impact of product quality incidents and cumulative costs to MPC.
The performance levels for each metric were established for 2019 by evaluating factors such as performance achieved in the prior year(s), anticipated challenges for 2019, MPC's business plan and MPC’s overall strategy. At the time the performance levels were set, the threshold levels were viewed as likely achievable, the target levels were viewed as challenging but achievable, and the maximum levels were viewed as extremely difficult to achieve.
The remaining 30% of MPC company performance is evaluated by MPC’s Compensation Committee based upon a number of discretionary factors, including business results in light of opportunities and challenges encountered during the year and adjustments due to the volatility in petroleum-related commodity prices throughout the year, which makes it difficult to establish reliable, pre-determined goals and individual performance achievements. Key factors considered for 2019 included:
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MPC achieved full-year earnings for 2019 of $2.6 billion.
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MPC’s sustained focus on shareholder returns, with $3.3 billion returned to shareholders through dividends and share repurchases.
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Successful integration of Andeavor into MPC, with the synergies realized well over first-year target.
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Successful merger of ANDX into MPLX.
2019 NEO Individual Performance
In addition to an evaluation of MPC company performance, MPC’s Compensation Committee reviews the NEOs’ performance, both collectively as a team and individually, in executing MPC’s and our business objectives. As a team, our NEOs focused on enhancing value for MPC’s shareholders and our unitholders in the following general categories:
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Enhancement of MPC shareholder and MPLX unitholder value through return of capital and unlocking midstream asset value.
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Successful integration of Andeavor and ANDX into MPC and MPLX operations.
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Excellence in environmental, personal safety and process safety improvement.
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Talent development, retention, succession and acquisition.
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System integration, optimization and removing bottlenecks.
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Growth through organic expansion and acquisition opportunities.
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Growth of market share for gasoline and diesel.
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Progress on diversity and inclusion initiatives.
In addition to these areas of general team focus, MPC’s Compensation Committee evaluated our NEOs based upon their responsibility for certain strategic projects and initiatives and their contribution to the successful execution of MPC’s and our business objectives.
ACB Payments for 2019
In February 2020, MPC's Compensation Committee certified the results under the performance metrics for the 2019 ACB program and, taking into consideration MPC's performance relative to the pre-established metrics, the key factors discussed above and each NEO's organizational and individual performance, awarded the following amounts under the ACB program to our NEOs for 2019:
*
Mr. Hennigan’s Target Bonus amount was adjusted to reflect his change in base salary and bonus target as he transitioned from his role as our President to service as our President and CEO.
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including base salary and ACB payouts, of Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table and in the “2019 Summary Compensation Table” below at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under our omnibus agreement.
MPLX Long-Term Incentive Compensation Program
Our long-term incentive (“LTI”) compensation program is designed to promote achievement of our long-term business objectives by linking our NEOs’ compensation directly to long-term company and equity performance, thereby strengthening alignment between our NEOs’ interests and our unitholders’ interests. Awards to our NEOs under our LTI program are granted by a committee of our Board comprised of the independent directors (the “MPLX Committee”) following a recommendation by MPC's Compensation Committee. For 2019, the MPLX Committee determined that our NEOs would receive 50% of their MPLX LTI award in the form of performance units and 50% in the form of phantom units.
MPLX Performance Units align our NEOs’ long-term interests with the long-term interests of our unitholders by conditioning payout on the performance of our total unitholder return and distributable cash flow relative to that of our peers over a three-year period.
MPLX Phantom Units promote our NEOs’ ownership of our common units, strengthening alignment between our NEOs’ interests and the interests of our unitholders, and help them comply with our unit ownership guidelines.
See the “2019 Grants of Plan-Based Awards” table and accompanying narrative below for more information about the specific awards granted to our NEOs in 2019.
2017 MPLX Performance Unit Payouts
The 2017 performance units, awarded in February 2017 to certain of our NEOs as part of our 2017 LTI program, were based 50% on our total unitholder return (“TUR”) relative to a peer group of midstream companies and 50% on a metric that measures the growth of our distributable cash flow (“DCF”), in each case measured over a three-year performance cycle. The MPLX Committee believes the relative TUR and DCF metrics are important indicators of performance as they are commonly used by unitholders to measure a master limited partnership’s performance against others within the same industry.
TUR Calculation
Measurement Periods
(Ending Unit Price - Beginning Unit Price) + Cumulative Cash Distributions
First 12 months
Beginning Unit Price
Second 12 months
The beginning and ending unit price is the average of each company’s closing unit price for the 20 trading days immediately preceding each applicable date.
Third 12 months
Entire 36-month period
2017 MPLX Performance Unit Peer Group
Andeavor Logistics LP*
Enterprise Products Partners L.P.
Valero Energy Partners LP*
Buckeye Partners, L.P.*
Magellan Midstream Partners, L.P.
Western Midstream Operating, LP
Enbridge Energy Partners, L.P.**
Phillips 66 Partners LP
Williams Partners L.P.**
Energy Transfer Partners, L.P.**
Plains All American Pipeline, L.P.
*Removed effective January 1, 2019 due to industry consolidation.
**Removed effective January 1, 2018 due to industry consolidation.
Our relative TUR performance percentile was measured for each measurement period, with the payout for performance between quartiles determined using linear interpolation:
*Increased to the 30th percentile for awards granted in 2018 and thereafter.
The DCF metric threshold, target and maximum levels were calculated by applying 8%, 10% and 12% compound annual growth rates, respectively, over the DCF per MPLX common unit at December 31, 2016 ($2.35), with the payout for performance between quartiles determined using linear interpolation:
In January 2020, the MPLX Committee certified the final relative TUR and DCF results for the 2017 MPLX performance units:
Each MPLX 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). The 2017 MPLX performance units final payout percentage was determined by averaging the TUR payout percentage and the DCF payout percentage. Based on the resulting average, each MPLX performance unit granted was multiplied by 144.38%, and the MPLX Committee approved the following payouts to our participating NEOs:
The 2017 MPLX performance units settled 25% in MPLX common units and 75% in cash. MPLX performance units granted to our NEOs in 2018 and 2019 remain outstanding. See the “Outstanding Equity Awards at 2019 Fiscal Year-End” table below for additional information about these awards.
MPC Long-Term Incentive Compensation Program
As part of their total equity package, our NEOs also receive LTI awards from MPC. For 2019, MPC's Compensation Committee determined that our NEOs would receive 50% of their MPC LTI award in the form of MPC performance units, 30% in the form of MPC stock options and 20% in the form of MPC restricted stock.
MPC Performance Units align our NEOs’ long-term interests with MPC’s shareholders’ long-term interests by conditioning payout on the performance of MPC’s total shareholder return relative to that of MPC’s peers over a three-year period. The percentage shown does not include a special grant in 2019 of additional synergy performance units intended to promote the capture of synergies following MPC’s acquisition of Andeavor in October 2018. These awards are discussed in more detail below.
MPC Stock Options drive behaviors and actions that enhance long-term MPC shareholder value and are inherently performance-based, as MPC’s stock price must increase before the NEO can recognize any benefit.
MPC Restricted Stock/Restricted Stock Units (“RSUs”) promote our NEOs’ ownership of MPC’s common stock, aid in retention, and help our NEOs comply with MPC’s stock ownership guidelines.
In addition to the annual awards described above, in 2019 MPC’s Compensation Committee made a special grant of MPC synergy performance units designed to promote the capture of synergies following MPC’s acquisition of Andeavor in 2018. These awards are discussed in more detail below. See the “2019 Grants of Plan-Based Awards” table and the accompanying narrative below for more information about the specific awards granted to our NEOs in 2019.
2017 MPC Performance Unit Payouts
The 2017 MPC performance units, awarded by MPC’s Compensation Committee in February 2017 to certain of our NEOs as part of MPC’s 2017 LTI program, evaluated MPC’s total shareholder return (“TSR”) relative to a peer group of petroleum industry competitors and a market index over a 36-month performance cycle. This relative evaluation recognizes the cyclical nature of MPC’s business and commodity prices and prevents volatility from directly advantaging or disadvantaging the payout percentage.
TSR Calculation
Measurement Periods
(Ending Stock Price - Beginning Stock Price) + Cumulative Cash Dividends
First 12 months
Beginning Stock Price
Second 12 months
The beginning and ending stock price is the average of each company’s closing stock price for the 20 trading days immediately preceding each applicable date.
Third 12 months
Entire 36-month period
2017 MPC Performance Unit Peer Group
Andeavor*
PBF Energy Inc.
Valero Energy Corporation
Chevron Corporation
Phillips 66
S&P 500 Energy Index
HollyFrontier Corporation
*Removed effective January 1, 2018 due to industry consolidation.
MPC’s relative TSR performance percentile was measured for each measurement period, with the payout for performance between quartiles determined using linear interpolation:
*Increased to 30th percentile for awards granted in 2018 and thereafter.
In January 2020, MPC’s Compensation Committee certified the final TSR results for the 2017 MPC performance units:
Each MPC 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). Based on the resulting average, each performance unit granted was multiplied by 110.72%, and MPC’s Compensation Committee approved the following payouts to our participating NEOs:
The 2017 MPC performance units settled 25% in MPC common stock and 75% in cash. MPC performance units granted to our NEOs in 2018 and 2019 remain outstanding. See the “Outstanding Equity Awards at 2019 Fiscal Year-End” table below for additional information about these awards.
MPC Synergy Performance Unit Payouts
In January 2019, MPC’s Compensation Committee awarded our NEOs synergy performance units under a new performance unit incentive program intended to promote MPC’s realization of annual run-rate synergies in connection with the integration of Andeavor, which MPC acquired October 1, 2018. The MPC synergy performance units are 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.
The MPC synergy performance units generally vest and are payable following completion of each performance period. Earlier vesting may 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). In February 2020, MPC’s Compensation Committee certified the final synergy capture performance for the October 1, 2018 through December 31, 2019 performance period at $1,404 million, which was above the maximum performance level, and approved the following payouts:
As noted above in “Compensation Decisions and Allocation,” the non-equity elements, including the MPC synergy performance unit payouts, of Mr. Swearingen’s and Ms. Gagle’s compensation are reflected in this table and in the “2019 Summary Compensation Table” below at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under our omnibus agreement.
The MPC synergy performance units for the January 1, 2020 through December 31, 2020 and January 1, 2021 through December 31, 2021 performance periods remain outstanding. See the “Outstanding Equity Awards at 2019 Fiscal Year-End” table below for additional information about these awards.
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 or us. 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.
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 2019” and “2019 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.”
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 officer 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.
Reportable values for these perquisite programs, based on the incremental costs to MPC, are included in the “All Other Compensation” column of the “2019 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 hold a specified level of MPLX common units. The targeted levels vary depending upon the executive’s position and responsibilities:
Each executive is expected to meet these guidelines within five years of his or her assumption of the applicable position. The guidelines also require that these officers hold all common units distributed in settlement of phantom units or performance units for a minimum of one year following the vesting date. Compliance with these guidelines is assessed annually. As of the most recent assessment in February 2020, all of our NEOs had met their unit ownership guidelines.
Prohibition on Derivatives and Hedging
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 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 is determined that a forfeiture event has occurred, an executive officer’s unvested phantom units and performance units would be subject to immediate forfeiture. If a forfeiture event occurred either while the executive officer was employed, or within three years after termination of employment, and the executive officer has received any payment in settlement of performance units, we may recoup an amount in cash or units up to the amount paid in settlement of the performance units.
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-Based Risk Assessment
Our Chairman and the independent directors of our Board 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. Our Chairman and the independent directors of our Board completed their review of our 2019 programs in February 2020, and 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
Compensation matters are determined by Mr. Heminger, our Chairman, and the independent directors of our Board. See “Director Independence” in Item 10. Directors, Executive Officers and Corporate Governance for more information about our independent directors. Mr. Heminger is also an executive officer and director of MPC. During 2019, none of our other executive officers served as a member of a compensation committee or board of directors of another entity that has an executive officer serving as a member of our Board.
COMPENSATION COMMITTEE REPORT
Our Chairman and independent directors have reviewed and discussed the Executive Compensation Discussion and Analysis for 2019 with management and, based on such review and discussions, recommended to the Board that the Executive Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2019.
Gary R. Heminger, Chairman
Michael L. Beatty
Christopher A. Helms
Garry L. Peiffer
Dan D. Sandman
J. Michael Stice
John P. Surma
EXECUTIVE COMPENSATION TABLES
2019 SUMMARY COMPENSATION TABLE
The following table provides information regarding compensation for our 2019 NEOs for the years shown:
Salary shows the actual amount earned during the year. With respect to Mr. Heminger, amounts reflect the annualized fixed fee we pay MPC for his services under an omnibus agreement. With respect to Mr. Swearingen and Ms. Gagle, amounts are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us under our omnibus agreement for each applicable year. With respect to the other NEOs, amounts reflect actual salary earned during each applicable year. Compensation is reviewed after the end of each year, and salary increases, if any, are generally effective April 1 of the following year. See the base salary overview in the CD&A for additional information on base salaries for 2019.
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”). See Item 8. Financial Statements and Supplementary Data, Note 21 of this report and Note 24 to MPC’s financial statements
included in its Annual Report on Form 10-K for the year ended December 31, 2019 for assumptions used to determine the values of these awards.
Performance Units granted in 2019 are included in the Stock Awards column for 2019. Their maximum value, assuming the highest level of performance achieved, is:
Non-Equity Incentive Plan Compensation reflects the total ACB award earned for the year indicated, paid the following year. Amounts for 2019 also include payouts under the synergy performance units for the performance period from October 1, 2018 through December 31, 2019. ACB and synergy performance unit amounts for Mr. Swearingen and Ms. Gagle reflect 75% and 50%, respectively, of the total value of their awards to reflect the portions of their time allocated to us under the omnibus agreement.
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 2019” 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. For Mr. Swearingen and Ms. Gagle, these amounts are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us under the omnibus agreement.
All Other Compensation aggregates contributions to defined contribution plans and the limited perquisites MPC offers to our NEOs, which are described in more detail in the perquisites overview in the CD&A.
Company Contributions to Defined Contribution Plans reflect MPC’s contributions under our tax-qualified retirement plans and related nonqualified deferred compensation plans. For Mr. Swearingen and Ms. Gagle, these amounts are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under the omnibus agreement. See “Post-Employment Benefits for 2019” and “2019 Nonqualified Deferred Compensation” for more information.
Other reflects reimbursement for the following amounts in connection with Mr. Hennigan’s 2017 move to our headquarters in Findlay, Ohio: $2,323 in reimbursement for relocation expenses and $1,851 in reimbursement for taxes due on the relocation reimbursement. The 2018 amount in the Summary Compensation Table for Mr. Hennigan includes $10,000 in reimbursement for relocation expenses and $7,968 in reimbursement for taxes due on the relocation reimbursement that were not previously reported in our Annual Report on Form 10-K for the year ended December 31, 2018.
2019 GRANTS OF PLAN-BASED AWARDS
The following table provides information regarding all MPLX plan-based awards granted by the MPLX Committee to our NEOs in 2019, as well as all MPC plan-based awards, including cash-based incentive awards and equity-based awards, granted by MPC’s Compensation Committee to our NEOs in 2019.
Approval Dates. The MPC awards granted on February 1, 2019 and March 1, 2019 were approved by MPC’s Compensation Committee on January 26, 2019 and February 26, 2019, respectively. The MPLX awards granted on March 1, 2019 were approved by the MPLX Committee on February 27, 2019.
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 MPC’s common stock on the grant date. Option holders do not have voting rights or receive dividends on the underlying stock.
MPC Restricted Stock generally vests in equal installments on the first, second and third anniversaries of the grant date. Unvested restricted stock awards accrue dividends, which are paid on the scheduled vesting dates. Holders of unvested restricted stock have voting rights.
MPC Performance Units generally vest following a 36-month performance period and are settled 25% in MPC common stock and 75% in cash. Unvested performance units do not receive dividends and do not have voting rights. The target amounts shown reflect the number of performance units granted, each of which has a target value of $1.00. The threshold, which is the minimum possible payout, is achieved when the payout percentage is 50% for one TSR measurement period and 0% for the other three TSR measurement periods, resulting in an average payout percentage of 12.5%. The maximum payout is 200% of target.
MPC Synergy Performance Units vest upon completion of each performance period and are settled in cash. Earlier vesting may 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. The performance periods are described in our CD&A. The target amounts shown reflect the number of performance units granted, at $1.00 per unit. No threshold amount is disclosed as MPC’s Compensation Committee has discretion to award nothing under the synergy performance units. 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.
MPLX Performance Units generally vest following a 36-month performance period and are settled 25% in MPLX common units and 75% in cash. Unvested performance units do not receive cash distributions or have voting rights. The target amounts shown reflect the number of performance units granted, each of which has a target value of $1.00. The threshold, which is the minimum possible payout, is achieved when the payout percentage is 0% for the DCF metric, 50% for one TUR measurement period and 0% for the other three TUR measurement periods, resulting in an average payout percentage of 6.25%. The maximum payout is 200% of target.
Modified Vesting Dates. To promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for MPC stock options, MPC restricted stock, MPC performance units, MPLX phantom units and MPLX performance units granted in 2017, 2018 and 2019 were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC.
Grant Date Fair Value reflects the total grant date fair value of each equity award calculated in accordance with FASB ASC Topic 718, as discussed further in Note 21 to our financial statements included in Item 8. Financial Statements and Supplementary Data and in Note 24 to MPC’s financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2019. The Black-Scholes value used for the MPC stock options was $14.34 per share. The MPC restricted stock value was based on the MPC common stock closing price of $62.68 on the grant date. The MPC performance units have a grant date fair value of $0.7196 per unit, using a Monte Carlo valuation model. The MPLX phantom unit value was based on the MPLX common unit closing price of $33.18 on the grant date. The portion (50%) of the MPLX performance units attributable to the TUR metric has a grant date fair value of $0.6848 per unit using a Monte Carlo valuation model, and the portion (50%) attributable to the DCF metric has grant date fair values of $1.00, $0.00 and $0.00 for the respective 2019, 2020 and 2021 performance years.
OUTSTANDING EQUITY AWARDS AT 2019 FISCAL YEAR-END
The following table provides information regarding the outstanding equity awards held by our NEOs as of December 31, 2019.
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; however, to promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for the 2017, 2018 and 2019 MPC stock options shown in this table were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The stock option exercise price is generally equal to the closing price of MPC’s common stock on the grant date. Option holders do not have voting rights or receive dividends on the underlying stock.
Unvested Shares and Units reflect the number of unvested MPLX phantom units and shares of MPC restricted stock held on December 31, 2019. Phantom units and restricted stock generally vest in one-third increments on the first, second and third anniversaries of the grant date; however to promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for the 2017, 2018 and 2019 MPLX phantom units and MPC restricted stock awards shown in the following table were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The table below reflects the original vesting dates of these awards as they remain subject to distribution on their original vesting dates.
MPLX phantom unit and MPC restricted stock awards generally provide for full vesting upon termination of employment due to our general policy that our officers retire on the first day of the month after they reach age 65. Mr. Heminger became eligible for such retirement on October 1, 2018. Under applicable tax rules, this retirement eligibility caused him to “vest” in his phantom unit awards for payroll tax purposes, and in his MPC restricted stock awards for income tax and payroll tax (e.g., FICA taxes) purposes, notwithstanding that he continues to be employed, because there is no longer any substantial risk of forfeiture for these awards. While these awards continue to be reflected in this table, the portion used to pay the associated taxes has been excluded from this table, and is instead included in the “Option Exercises and Units Vested in 2019” table below.
Market Value of Unvested Shares reflects the aggregate value of all unvested MPLX phantom units and MPC restricted stock held on December 31, 2019, using the MPLX closing unit price of $25.46 and the MPC closing stock price of $60.25 on that date.
Unvested Equity Incentive Plan Awards reflect the number of unvested MPLX performance units and MPC performance units held on December 31, 2019.
The MPLX performance units awarded in 2018 and 2019 have a 36-month performance cycle and settle 25% in MPLX common units and 75% in cash. Each performance unit has a target value of $1.00. Payout may vary from $0.00 to $2.00 per unit. Fifty percent of the payout will be determined based on MPLX’s TUR as compared to the applicable peer group, which for 2018 and 2019 was: Andeavor Logistics LP (removed effective January 1, 2019), Buckeye Partners, L.P. (removed effective January 1, 2019), Enterprise Products Partners LP, Magellan Midstream Partners, L.P., Phillips 66 Partners LP, Plains All American Pipeline, L.P., Valero Energy Partners LP (removed effective January 1, 2019), and Western Midstream Operating, LP. The other 50% is based on a DCF-per-MPLX-common-unit metric, which measures the growth of MPLX’s full-year DCF over the 36-month performance cycle. Performance units generally vest following a 36-month performance period; however, to promote the retention of Messrs. Hennigan, Floerke and Swearingen and Mses. Beall and Gagle, their award agreements for the 2018 and 2019 MPLX performance units shown in the table were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The performance cycles for these awards remain unchanged.
The MPC performance units awarded in March 2018 and 2019 have 36-month performance cycles and settle 25% in MPC common stock and 75% in cash. Each performance unit has a target value of $1.00. Payout may vary from $0.00 to $2.00 per unit and is tied to MPC’s TSR as compared to the applicable peer group. The 2018 peer group was: Andeavor (removed effective January 1, 2018), Chevron Corporation, HollyFrontier Corporation, PBF Energy, Phillips 66, Valero Energy Corporation and the S&P 500 Energy Index. The 2019 performance unit peer group added BP p.l.c. and Exxon Mobil Corporation. Performance units generally vest following a 36-month performance period; however, to promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for the 2018 and 2019 MPC performance units shown in the table were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. The performance cycles for these awards remain unchanged.
Market Value of Unvested Equity Incentive Plan Awards. Amounts shown for MPLX reflect the aggregate value of all MPLX performance units held on December 31, 2019, assuming payouts of 200.00% and 200.00% per unit for the 2018 and 2019 awards, respectively, which is the next higher performance achievement that exceeds the performance for these awards’ measurement period ended December 31, 2019. Amounts shown for MPC reflect the aggregate value of all MPC performance units held on December 31, 2019, assuming payouts of 200.00% and 200.00% per unit for the 2018 and 2019 awards, respectively, which is the next higher performance achievement that exceeds the performance for these awards’ measurement period ended December 31, 2019.
OPTION EXERCISES AND UNITS VESTED IN 2019
The following table provides information regarding MPC stock options exercised by our NEOs in 2019, as well as MPLX phantom units, MPLX performance units, MPC restricted stock and MPC performance units that vested in 2019.
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 Acquired on Vesting for Mr. Heminger include 1,696 MPLX phantom units used to pay the taxes associated with the vesting of certain awards due to his retirement eligibility, as discussed further under “Outstanding Equity Awards at 2019 Fiscal Year-End.”
Value Realized on Vesting reflects the actual pre-tax gain realized upon vesting of MPLX phantom units, MPLX performance units, MPC restricted stock and MPC performance units, which is the fair market value of the units/shares on the vesting date.
POST-EMPLOYMENT BENEFITS FOR 2019
2019 Pension Benefits
MPC provides tax-qualified retirement benefits to its employees, including our NEOs, under the MPC Retirement Plan. In addition, MPC sponsors the MPC Excess Benefit Plan for the benefit of a select group of management or highly compensated employees.
The following table reflects the actuarial present value of accumulated benefits payable to our NEOs under the MPC Retirement Plan and the defined benefit portion of the MPC Excess Benefit Plan as of December 31, 2019. These values have been determined using actuarial assumptions consistent with those used in MPC’s financial statements.
Dollar values for Mr. Swearingen and Ms. Gagle are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under our omnibus agreement.
Number of Years Credited Service shows the number of years the NEO has participated in the plan. Plan participation service used to calculate each participant’s benefit under the MPC Retirement Plan legacy final average pay formula was frozen as of December 31, 2009.
Present Value of Accumulated Benefit for the MPC Retirement Plan was calculated assuming a weighted average discount rate of 3.20%, the RP2000 mortality table for lump sums, a 90% lump sum election rate and retirement at age 62 (or current age, if later). Under the MPC Retirement Plan provisions and actuarial assumptions, the discount rate for lump sum calculations was 0.25%. See “MPC Retirement Plan” below for more detail on the formulas.
MPC Retirement Plan
In general, our NEOs are eligible to participate in the MPC Retirement Plan, which is a tax-qualified defined benefit retirement plan primarily designed to provide participants with income after retirement. The plan has both a “legacy” retirement benefit and a “cash balance” retirement benefit. Prior to 2010, the monthly benefit was determined under the MPC legacy benefit formula.
MPC Legacy Benefit Formula
1.6%
×
Monthly Final
Average Pay
×
Years of Participation
-
1.33%
×
Monthly Estimated Primary Social Security Benefit
×
Years of Participation
Monthly Benefit
Effective January 1, 2010, the formula was amended to (i) cease future accruals of additional participation years, and (ii) 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, 401(k) contributions to the MPC Thrift Plan and incentive compensation bonuses. Age continues to be updated under the formula.
Starting in 2010, benefit accruals are determined under a 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 Benefit
Pay Credit Percentage
7%
9%
11%
Participants in the plan become fully vested upon completing three years of vesting service. Normal retirement age under the plan is 65. However, retirement-eligible participants are able to retire and receive an unreduced benefit under the MPC legacy benefit formula after reaching 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 MPC legacy benefit formula is reduced as follows:
Of our NEOs providing a majority of their services to our business, only Mses. Beall and Gagle and Mr. Swearingen have accrued a benefit under the MPC legacy benefit formula. Mses. Beall and Gagle and Mr. Swearingen are currently eligible for early retirement benefits under the MPC legacy benefit formula.
Under the cash balance formula, plan participants receive pay credits based on age and cash balance service. For 2019, Mses. Beall and Gagle and Mr. Swearingen received pay credits equal to 11% of compensation, which is the highest level of pay credit available under the plan. Messrs. Hennigan 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 items listed above, excluding bonuses, for the MPC Retirement Plan, as well as deferred compensation contributions, for the highest consecutive 36-month period over the 10-year period up to December 31, 2012. This plan also provides an enhancement for executive officers using the three highest bonuses earned over the 10-year period up to December 31, 2012, instead of the consecutive bonus formula in place for non-officers. MPC believes this enhancement is appropriate in light of the greater volatility of executive officer bonuses. As Messrs. Hennigan and Floerke have not accrued a benefit under the Marathon legacy benefit formula, they are not eligible for this enhancement.
MPC Thrift 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 ($280,000 for 2019). Beginning in 2020, 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 ($285,000 for 2020). Employer matching contributions are made on such elective deferrals 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.
2019 NONQUALIFIED DEFERRED COMPENSATION
The following table provides information regarding MPC’s nonqualified savings and deferred compensation plans.
Amounts for Mr. Swearingen and Ms. Gagle are shown at 75% and 50%, respectively, to reflect the portions of their time allocated to us for 2019 under our omnibus agreement.
Executive Contributions are also included in the “Salary” and “Non-Equity Incentive Plan Compensation” columns of the “2019 Summary Compensation Table.”
Company Contributions are also included in the “All Other Compensation” column of the “2019 Summary Compensation Table.”
Aggregate Withdrawals/Distributions represent the payment of distribution equivalents accrued on non-forfeitable awards.
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:
MPC Excess Benefit Plan (Defined Contribution Portion)
Certain highly compensated non-officer employees (and, prior to January 1, 2006, executive officers who elected not to participate in the MPC Deferred Compensation Plan), 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 2.23% for the year ended December 31, 2019. All plan distributions are paid in a lump sum following the participant’s separation
from service. Our NEOs no longer participate in the defined contribution portion of the MPC Excess Benefit Plan. All nonqualified employer matching contributions for our NEOs now accrue under the MPC 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. Participants may defer up to 20% of their salary and bonus each year in a tax-advantaged manner. Deferral elections are made in December of each year 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 (currently 117%) 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 generally receive payment of their plan benefits in a lump sum following separation from service.
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.
POTENTIAL PAYMENTS UPON A TERMINATION OR CHANGE IN CONTROL
The following table provides information regarding the amount of compensation payable to each of our NEOs under the specified termination scenarios, assuming that the applicable termination event occurred on December 31, 2019, 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.
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. As
Mr. Heminger has reached age 65, his cash severance benefits have been reduced to zero. Ms. Beall’s benefit has been reduced as she is within three years of reaching age 65.
Pension Benefits for our NEOs are reflected in the “2019 Pension Benefits Table” above. Amounts in this table represent additional pension benefits attributable solely to the final average pay formula in the applicable plans. 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 0.25% for NEOs who are retirement eligible (taking into account the additional three years of age and service credit) and 0.25% for our NEOs who are not retirement eligible; the current lump-sum interest rate for the relevant plans; and a lump-sum form of benefit. Only Mses. Beall and Gagle and Mr. Swearingen are eligible for this enhanced benefit.
Accelerated Options. Vesting of MPC stock options is accelerated upon retirement or a change in control with a Qualified Termination. In addition, unvested MPC stock options granted in 2017, 2018 and 2019 to Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. Amounts shown reflect the value realized if accelerated stock options were exercised on December 31, 2019, taking into account the spread (if any) between the options’ exercise prices and the closing price of MPC’s common stock ($60.25) on December 31, 2019.
Accelerated Restricted Stock. Vesting of MPC restricted stock and MPLX phantom units is accelerated upon a change in control with a Qualified Termination. In addition, unvested MPC restricted stock and MPLX phantom units granted in 2017, 2018 and 2019 to Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. Amounts shown reflect the value realized if MPC restricted stock/stock units and MPLX phantom unit awards vested on December 31, 2019, taking into account the closing price of MPC’s common stock ($60.25) and MPLX common units ($25.46) on December 31, 2019. In the event of Mr. Floerke’s termination of employment for any reason other than for cause, the unvested MPLX phantom units he received as part of his retention award in 2015 will vest and become payable.
Accelerated Performance Units. In the event of a change in control and a Qualified Termination, unvested MPC performance units and MPLX performance units 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. In addition, unvested MPC performance units and MPLX performance units granted in 2017, 2018 and 2019 to Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC. Unvested MPC synergy performance units will vest and be paid out at the greater of target or actual synergy capture performance. Amounts reflect the MPC performance unit, MPLX performance unit and MPC synergy performance unit target amounts payable in a change in control scenario, with each performance unit having a target value of $1.00.
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, $1.8 million; Ms. Beall, $1.09 million; Mr. Swearingen, $1.05 million; Ms. Gagle $1.15 million; Mr. Floerke, $1.05 million.
Retirement
MPC’s employees, including our NEOs, 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, 2019, Messrs. Heminger and Swearingen and Mses. Beall and Gagle were retirement eligible. If an NEO retires on or after July 1 of the performance year, eligibility for a bonus under MPC’s ACB program is at the discretion of MPC’s Compensation Committee. Upon retirement, our NEOs are entitled to receive their vested benefits that have accrued under MPC’s employee and executive benefit programs. For more information about these retirement and deferred compensation programs, see “2019 Pension Benefits” and “2019 Nonqualified Deferred Compensation.”
In addition, upon retirement, our NEOs’ unvested MPC stock options become exercisable according to the grant terms. Unvested MPC restricted stock and MPLX phantom units are forfeited upon retirement (except in the case of a 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 the MPLX Committee (MPC’s Compensation Committee, in the case of MPC 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.
Other Termination
Neither MPC nor we generally enter into employment or severance agreements with our NEOs. An NEO whose employment is terminated 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 an amount between eight and 62 weeks of salary based either on service or salary level, in each case, at the discretion of MPC’s Compensation Committee.
Upon an NEO’s voluntary termination, or involuntary termination for cause, unvested LTI awards, including vested but unexercised MPC stock options, generally are forfeited unless provided otherwise in the applicable award agreement. Upon involuntary termination of an NEO without cause, vested MPC options are exercisable for 90 days following termination. To promote the retention of Messrs. Hennigan, Swearingen and Floerke and Mses. Beall and Gagle, their award agreements for MPLX phantom units, MPLX performance units, MPC stock options, MPC restricted stock and MPC performance units granted in 2017, 2018 and 2019 were amended such that any such unvested awards now become non-forfeitable on the earlier of December 31, 2020 or the date of such executive’s involuntary termination by MPC.
Death
In the event of death or disability, our NEOs (or their beneficiaries) are entitled to the vested benefits they have accrued under MPC’s employee benefits 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 Plans
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”). Benefits under each plan are payable only upon a change in control and a Qualified Termination. 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.
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
●
Termination for cause
●
Voluntary termination without good reason (which 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 after age 65
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:
The MPLX CIC Plan also provides that NEOs who don’t technically incur a Qualifying 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.
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.
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 2019:
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. The annual limit is applied based on the date of the director’s gift to the institution. Due to processing delays, the actual amount paid out on behalf of a director may exceed $10,000 in a given year.
2019 Director Compensation Table
The following table shows compensation earned by or paid to our non-employee directors during 2019.
Fees Earned or Paid in Cash reflect (i) cash retainers earned for Board service in 2019, (ii) for each of Messrs. Beatty, Helms, and Sandman, $45,000 in meeting fees for Conflicts Committee meetings held during 2019, (iii) for Mr. Semple, $62,500 in compensation for service as our Representative Observer, in which role he attends certain MPC Board and committee meetings as a liaison between the MPC Board and us, and $25,000 for his service in the same capacity with respect to an MPC Board special committee.
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, 2019 is: Messrs. Helms, Sandman, and Surma, 19,192; Mr. Peiffer, 16,091; Mr. Beatty, 12,942; Mr. Semple, 10,190; and Mr. Stice, 5,726.
All Other Compensation reflects contributions to educational institutions under MPC’s matching gifts program.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Security Ownership of Directors and Executive Officers
The following table sets forth the number of our common units and shares of MPC common stock beneficially owned as of January 31, 2020 by each director and NEO, and by all 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 January 31, 2020, there were 1,058,401,784 MPLX common units outstanding (including 665,997,540 common units held by MPC and its affiliates) and 649,486,869 shares of MPC common stock outstanding.
* Less than 1% of common units or common shares outstanding, as applicable.
MPLX Common Unit ownership amounts include:
•
Phantom unit awards, which settle in common units upon a director’s retirement from service on the Board, as follows: Mr. Beatty, 14,004; Mr. Helms, 20,253; Mr. Peiffer, 17,153; Mr. Sandman, 20,253; Mr. Semple, 12,246; Mr. Stice, 8,497; Mr. Surma, 24,002.
•
Phantom unit awards, which may be forfeited under certain conditions, as follows: Ms. Beall, 10,773; Mr. Floerke, 47,074; Ms. Gagle, 14,122; Mr. Hennigan, 113,543; Mr. Swearingen, 9,984; Mr. Templin, 30,221; all other executives, 4,613.
•
For Mr. Heminger, 77,852 phantom unit awards, which are no longer subject to forfeiture because Mr. Heminger has reached mandatory retirement age.
•
Common units indirectly beneficially held in trust as follows: Ms. Beall, 10,000; Mr. Heminger, 174,515; Mr. Peiffer, 68,497; Mr. Semple, 527,517; Mr. Stice, 700.
•
For Messrs. Semple and Templin, common units held by or with spouse, with spouse as co-trustee or by trust for the benefit of spouse.
MPC Common Stock ownership amounts include:
•
All stock options exercisable within 60 days of January 31, 2020 as follows: Ms. Beall, 75,188; Mr. Floerke, 15,831; Ms. Gagle, 94,994; Mr. Heminger, 2,541,680; Mr. Hennigan, 40,791; Mr. Swearingen, 185,974; Mr. Templin, 541,751; all other executive officers, 4,106. Includes 359,773 stock options exercisable by the applicable executive officers but not in the money as of January 31, 2020.
•
Shares of common stock indirectly beneficially held in trust as follows: Ms. Beall, 32,208; Mr. Heminger, 206,202; Mr. Peiffer, 63,394; Mr. Surma, 10,000.
•
For Messrs. Surma and Templin, shares of common stock held by or with spouse, with spouse as co-trustee 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 or observer status, as follows: Mr. Semple, 4,892; Mr. Stice, 7,713; Mr. Surma, 37,412.
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, 2019:
Percent of Common Units is based on common units representing limited partner interests (“MPLX LP common units”) outstanding as of February 17, 2020.
Marathon Petroleum Corporation. The MPLX common units are directly held by MPC Investment LLC, MPLX GP LLC, MPLX Logistics Holdings LLC, Tesoro Logistics GP, LLC and Western Refining Southwest, Inc. Marathon Petroleum Corporation is the ultimate parent company of MPC Investment LLC, MPLX GP LLC, MPLX Logistics Holdings LLC, Tesoro Logistics GP, LLC and Western Refining Southwest, Inc. and may be deemed to beneficially own the MPLX LP common units directly held by these entities.
Securities Authorized for Issuance Under Equity Compensation Plans
The following table provides information as of December 31, 2019, with respect to common units that may be issued under the MPLX LP 2012 Plan and the MPLX LP 2018 Plan:
Number of Securities to Be Issued includes:
•
1,109,598 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, 2019.
•
315,248 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2019, pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan based on the closing price of our common units on December 31, 2019, of $25.46 per unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and Supplementary Data - Note 21 for more information on performance unit awards granted under the MPLX 2012 Plan and the MPLX 2018 Plan.
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 119,207 as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2019, pursuant to the MPLX 2018 Plan based on the closing price of our common units on December 31, 2019, of $25.46 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. See Item 8. Financial Statements and Supplementary Data - Note 21 for more information on performance unit awards issued pursuant to the MPLX 2018 Plan.
Item 13.
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 5% 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 5% 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;
•
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 the Initial 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 17, 2020, MPC owned through its affiliates 665,997,540 of our common units, representing approximately 63% 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 2019. 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 2019, we distributed approximately $1,529 million with respect to MPC’s limited partner interest.
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 2019 was $4 million.
Acquisition of ANDX
We completed the acquisition of ANDX (the “Merger”) on July 30, 2019. Prior to the Merger, MPC owned through its affiliates approximately 64% of ANDX’s outstanding common units and 100% of its general partner. 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. Each ANDX common unit held by certain affiliates of MPC was converted into the right to receive 1.0328 MPLX common units. This resulted in the issuance of approximately 102 million MPLX common units to public unitholders and approximately 161 million MPLX common units to MPC. The units issued to MPC were valued at approximately $4.7 billion as of the transaction closing.
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 Note 6 - Related Party Agreements and Transactions in the Notes to Consolidated Financial Statements, 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.
Item 14.
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, 2019, and December 31, 2018:
Audit fees for the years ended December 31, 2019, and December 31, 2018, were primarily for professional services rendered for the audit of the financial statements and of internal controls 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.
Audit-Related fees for the year ended December 31, 2018, were for professional services rendered in relation to updating accounting processes and procedures in order to comply with new accounting pronouncements.
Tax fees for the years ended December 31, 2019, and December 31, 2018, 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, 2019, and December 31, 2018, 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 2019 and 2018, 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.
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
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.
Exhibits:
†
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.
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.
Item 16. Form 10-K Summary
Not applicable.
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 28, 2020
MPLX LP
By:
MPLX GP LLC
Its general partner
By:
/s/ C. Kristopher Hagedorn
C. Kristopher Hagedorn
Vice President and Controller of MPLX GP LLC
(the general partner of MPLX LP)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 28, 2020 on behalf of the registrant and in the capacities indicated.
Signature
Title
/s/ Michael J. Hennigan
Director, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) (principal executive officer)
Michael J. Hennigan
/s/ Pamela K.M. Beall
Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) (principal financial officer)
Pamela K.M. Beall
/s/ C. Kristopher Hagedorn
Vice President and Controller of MPLX GP LLC (the general partner of MPLX LP) (principal accounting officer)
C. Kristopher Hagedorn
*
Chairman of the Board of Directors of MPLX GP LLC (the general partner of MPLX LP)
Gary R. Heminger
*
Director of MPLX GP LLC (the general partner of MPLX LP)
Michael L. Beatty
*
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)
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
*
Director of MPLX GP LLC (the general partner of MPLX LP)
Donald C. Templin
*
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.