Mplx LP 10-Q for FY2023 Q2
Mplx LP (MPLX)
10-Q
2023-08-01
For: 2023-06-30
View Original
Added on
April 12, 2026
About this 10-Q
Mplx LP filed this 10-Q on August 1, 2023, covering the quarter ended June 30, 2023 (FY2023 Q2).
Headline figures
Quarter ended June 30, 2023, as reported in this filing, compared with the same period a year earlier where the filing states it.
- Revenue
- $2.69B
- down 8.5% from $2.94B a year earlier
- Net income
- $933M
- up 6.6% from net income of $875M a year earlier
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________
FORM 10-Q
____________________________________________
| (Mark One) | |||||
| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended June 30, 2023
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from to
Commission file number 001-35714
_____________________________________________
(Exact name of registrant as specified in its charter)
_____________________________________________
| (State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |||||||||||||||||||
| (Address of principal executive offices) | (Zip code) | ||||||||||||||||
(419 ) 421-2414
(Registrant’s telephone number, including area code)
_____________________________________________
| Securities Registered pursuant to Section 12(b) of the Act | ||||||||
| Title of each class | Trading symbol(s) | Name of each exchange on which registered | ||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files.) Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| x | Accelerated filer | ☐ | Non-accelerated filer | ☐ | |||||||||||||||||||
| Smaller reporting company | Emerging growth company | |||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act) Yes ☐ No x
MPLX LP had 1,001,216,867 common units outstanding as of July 26, 2023.
Table of Contents
| Page | ||||||||
| Item 1. | ||||||||
| Item 2. | ||||||||
| Item 3. | ||||||||
| Item 4. | ||||||||
| Item 1. | ||||||||
| Item 1A. | ||||||||
| Item 5. | ||||||||
| Item 6. | ||||||||
Unless otherwise stated or the context otherwise indicates, all references in this Form 10-Q to “MPLX LP,” “MPLX,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its consolidated subsidiaries. References to our sponsor and customer, “MPC,” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership.
1
Glossary of Terms
The abbreviations, acronyms and industry technology used in this report are defined as follows:
| ASC | Accounting Standards Codification | ||||
| ASU | Accounting Standards Update | ||||
| Barrel | One stock tank barrel, or 42 U.S. gallons of liquid volume, used in reference to crude oil or other liquid hydrocarbons | ||||
| Btu | One British thermal unit, an energy measurement | ||||
| DCF (a non-GAAP financial measure) | Distributable Cash Flow | ||||
| EBITDA (a non-GAAP financial measure) | Earnings Before Interest, Taxes, Depreciation and Amortization | ||||
| FASB | Financial Accounting Standards Board | ||||
| FCF (a non-GAAP financial measure) | Free Cash Flow | ||||
| GAAP | Accounting principles generally accepted in the United States of America | ||||
| G&P | Gathering and Processing segment | ||||
| L&S | Logistics and Storage segment | ||||
| mbpd | Thousand barrels per day | ||||
| MMBtu | One million British thermal units, an energy measurement | ||||
| MMcf/d | One million cubic feet of natural gas per day | ||||
| NGL | Natural gas liquids, such as ethane, propane, butanes and natural gasoline | ||||
| SEC | U.S. Securities and Exchange Commission | ||||
| SOFR | Secured Overnight Financing Rate | ||||
| VIE | Variable interest entity | ||||
2
Part I—Financial Information
Item 1. Financial Statements
MPLX LP
Consolidated Statements of Income (Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions, except per unit data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||
| Service revenue | $ | $ | $ | $ | |||||||||||||||||||
| Service revenue - related parties | |||||||||||||||||||||||
| Service revenue - product related | |||||||||||||||||||||||
| Rental income | |||||||||||||||||||||||
| Rental income - related parties | |||||||||||||||||||||||
| Product sales | |||||||||||||||||||||||
| Product sales - related parties | |||||||||||||||||||||||
| Sales-type lease revenue | |||||||||||||||||||||||
| Sales-type lease revenue - related parties | |||||||||||||||||||||||
| Income from equity method investments | |||||||||||||||||||||||
| Other income (loss) | ( | ||||||||||||||||||||||
| Other income - related parties | |||||||||||||||||||||||
| Total revenues and other income | |||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||
| Cost of revenues (excludes items below) | |||||||||||||||||||||||
| Purchased product costs | |||||||||||||||||||||||
| Rental cost of sales | |||||||||||||||||||||||
| Rental cost of sales - related parties | |||||||||||||||||||||||
| Purchases - related parties | |||||||||||||||||||||||
| Depreciation and amortization | |||||||||||||||||||||||
| General and administrative expenses | |||||||||||||||||||||||
| Other taxes | |||||||||||||||||||||||
| Total costs and expenses | |||||||||||||||||||||||
| Income from operations | |||||||||||||||||||||||
| Related-party interest and other financial costs | |||||||||||||||||||||||
| Interest expense, net of amounts capitalized | |||||||||||||||||||||||
| Other financial costs | |||||||||||||||||||||||
| Income before income taxes | |||||||||||||||||||||||
| Provision for income taxes | |||||||||||||||||||||||
| Net income | |||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | |||||||||||||||||||||||
| Net income attributable to MPLX LP | |||||||||||||||||||||||
| Less: Series A preferred unitholders interest in net income | |||||||||||||||||||||||
| Less: Series B preferred unitholders interest in net income | |||||||||||||||||||||||
| Limited partners' interest in net income attributable to MPLX LP | $ | $ | $ | $ | |||||||||||||||||||
| Per Unit Data (See Note 6) | |||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | |||||||||||||||||||||||
| Common - basic | $ | $ | $ | $ | |||||||||||||||||||
| Common - diluted | $ | $ | $ | $ | |||||||||||||||||||
| Weighted average limited partner units outstanding: | |||||||||||||||||||||||
| Common - basic | |||||||||||||||||||||||
| Common - diluted | |||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
3
MPLX LP
Consolidated Statements of Comprehensive Income (Unaudited)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income | $ | $ | $ | $ | |||||||||||||||||||
| Other comprehensive income, net of tax: | |||||||||||||||||||||||
| Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax | |||||||||||||||||||||||
| Comprehensive income | |||||||||||||||||||||||
| Less comprehensive income attributable to: | |||||||||||||||||||||||
| Noncontrolling interests | |||||||||||||||||||||||
| Comprehensive income attributable to MPLX LP | $ | $ | $ | $ | |||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
4
MPLX LP
Consolidated Balance Sheets (Unaudited)
| (In millions) | June 30, 2023 | December 31, 2022 | |||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Receivables, net | |||||||||||
| Current assets - related parties | |||||||||||
| Inventories | |||||||||||
| Other current assets | |||||||||||
| Total current assets | |||||||||||
| Equity method investments | |||||||||||
| Property, plant and equipment, net | |||||||||||
| Intangibles, net | |||||||||||
| Goodwill | |||||||||||
| Right of use assets, net | |||||||||||
| Noncurrent assets - related parties | |||||||||||
| Other noncurrent assets | |||||||||||
| Total assets | |||||||||||
| Liabilities | |||||||||||
| Accounts payable | |||||||||||
| Accrued liabilities | |||||||||||
| Current liabilities - related parties | |||||||||||
| Accrued property, plant and equipment | |||||||||||
| Long-term debt due within one year | |||||||||||
| Accrued interest payable | |||||||||||
| Operating lease liabilities | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Long-term deferred revenue | |||||||||||
| Long-term liabilities - related parties | |||||||||||
| Long-term debt | |||||||||||
| Deferred income taxes | |||||||||||
| Long-term operating lease liabilities | |||||||||||
| Other long-term liabilities | |||||||||||
| Total liabilities | |||||||||||
| Commitments and contingencies (see Note 14) | |||||||||||
Series A preferred units ( | |||||||||||
| Equity | |||||||||||
Common unitholders - public ( | |||||||||||
Common unitholders - MPC ( | |||||||||||
Series B preferred units ( | |||||||||||
| Accumulated other comprehensive loss | ( | ( | |||||||||
| Total MPLX LP partners’ capital | |||||||||||
| Noncontrolling interests | |||||||||||
| Total equity | |||||||||||
| Total liabilities, preferred units and equity | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
5
MPLX LP
Consolidated Statements of Cash Flows (Unaudited)
| Six Months Ended June 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Operating activities: | |||||||||||
| Net income | $ | $ | |||||||||
| Adjustments to reconcile net income to net cash provided by operating activities: | |||||||||||
| Amortization of deferred financing costs | |||||||||||
| Depreciation and amortization | |||||||||||
| Deferred income taxes | ( | ||||||||||
| (Gain)/loss on disposal of assets | ( | ||||||||||
| Income from equity method investments | ( | ( | |||||||||
| Distributions from unconsolidated affiliates | |||||||||||
| Change in fair value of derivatives | ( | ( | |||||||||
| Changes in: | |||||||||||
| Receivables | ( | ||||||||||
| Inventories | ( | ( | |||||||||
| Accounts payable and accrued liabilities | ( | ||||||||||
| Assets/liabilities - related parties | |||||||||||
| Right of use assets/operating lease liabilities | |||||||||||
| Deferred revenue | |||||||||||
| All other, net | |||||||||||
| Net cash provided by operating activities | |||||||||||
| Investing activities: | |||||||||||
| Additions to property, plant and equipment | ( | ( | |||||||||
| Acquisitions, net of cash acquired | ( | ||||||||||
| Disposal of assets | |||||||||||
| Investments in unconsolidated affiliates | ( | ( | |||||||||
| Net cash used in investing activities | ( | ( | |||||||||
| Financing activities: | |||||||||||
| Long-term debt borrowings | |||||||||||
| Long-term debt repayments | ( | ( | |||||||||
| Related party debt borrowings | |||||||||||
| Related party debt repayments | ( | ||||||||||
| Debt issuance costs | ( | ( | |||||||||
| Unit repurchases | ( | ||||||||||
| Redemption of Series B preferred units | ( | ||||||||||
| Distributions to noncontrolling interests | ( | ( | |||||||||
| Distributions to Series A preferred unitholders | ( | ( | |||||||||
| Distributions to Series B preferred unitholders | ( | ( | |||||||||
| Distributions to unitholders and general partner | ( | ( | |||||||||
| Contributions from MPC | |||||||||||
| All other, net | ( | ( | |||||||||
| Net cash used in financing activities | ( | ( | |||||||||
| Net change in cash, cash equivalents and restricted cash | |||||||||||
| Cash, cash equivalents and restricted cash at beginning of period | |||||||||||
| Cash, cash equivalents and restricted cash at end of period | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
6
MPLX LP
Consolidated Statements of Equity and Series A Preferred Units (Unaudited)
| Partnership | ||||||||||||||||||||||||||||||||||||||||||||||||||
| (In millions) | Common Unit-holders Public | Common Unit-holder MPC | Series B Preferred Unit-holders | Accumulated Other Comprehensive Loss | Non-controlling Interests | Total | Series A Preferred Unit-holders | |||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2022 | $ | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Redemption of Series B preferred units | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Contributions | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2023 | $ | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Unit repurchases | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | ( | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Contributions | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2023 | $ | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | $ | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Unit repurchases | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | ( | ( | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Contributions | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ( | |||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at March 31, 2022 | $ | $ | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Net income | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Unit repurchases | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Distributions | ( | ( | ( | ( | ( | |||||||||||||||||||||||||||||||||||||||||||||
| Contributions | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at June 30, 2022 | ( | |||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
7
Notes to Consolidated Financial Statements (Unaudited)
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 that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. We are engaged in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products and renewables; the gathering, processing and transportation of natural gas; and the transportation, fractionation, storage and marketing of NGLs. MPLX’s principal executive office is located in Findlay, Ohio. MPLX was formed on March 27, 2012 as a Delaware limited partnership and completed its initial public offering on October 31, 2012.
Basis of Presentation
These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2022. The results of operations for the three and six months ended June 30, 2023 are not necessarily indicative of the results to be expected for the full year.
2. Accounting Standards
Not Yet Adopted
ASU 2023-01, Leases (Topic 842): Common Control Arrangements
In March 2023, the FASB issued an ASU to amend certain provisions of ASC 842 that apply to arrangements between related parties under common control. The ASU amends the accounting for the amortization period of leasehold improvements in common-control leases for all entities and requires certain disclosures when the lease term is shorter than the useful life of the asset. This ASU is effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. We do not expect the application of this ASU to have a material impact on our consolidated financial statements or financial disclosures.
8
3. Investments and Noncontrolling Interests
The following table presents MPLX’s equity method investments at the dates indicated:
| Ownership as of | Carrying value at | ||||||||||||||||||||||
| June 30, | June 30, | December 31, | |||||||||||||||||||||
| (In millions, except ownership percentages) | VIE | 2023 | 2023 | 2022 | |||||||||||||||||||
| L&S | |||||||||||||||||||||||
| Andeavor Logistics Rio Pipeline LLC | X | $ | $ | ||||||||||||||||||||
| Illinois Extension Pipeline Company, L.L.C. | |||||||||||||||||||||||
| LOOP LLC | |||||||||||||||||||||||
MarEn Bakken Company LLC(1) | |||||||||||||||||||||||
| Minnesota Pipe Line Company, LLC | |||||||||||||||||||||||
| Whistler Pipeline LLC | |||||||||||||||||||||||
Other(2) | X | ||||||||||||||||||||||
| Total L&S | |||||||||||||||||||||||
| G&P | |||||||||||||||||||||||
| Centrahoma Processing LLC | |||||||||||||||||||||||
| MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C | X | ||||||||||||||||||||||
| MarkWest Torñado GP, L.L.C. | X | ||||||||||||||||||||||
| MarkWest Utica EMG, L.L.C. | X | ||||||||||||||||||||||
| Rendezvous Gas Services, L.L.C. | X | ||||||||||||||||||||||
| Sherwood Midstream Holdings LLC | X | ||||||||||||||||||||||
| Sherwood Midstream LLC | X | ||||||||||||||||||||||
Other(2) | X | ||||||||||||||||||||||
| Total G&P | |||||||||||||||||||||||
| Total | $ | $ | |||||||||||||||||||||
(1) The investment in MarEn Bakken Company LLC includes our 9.19 percent indirect interest in a joint venture (“Dakota Access”) that owns and operates the Dakota Access Pipeline and Energy Transfer Crude Oil Pipeline projects, collectively referred to as the Bakken Pipeline system or DAPL.
(2) Some investments included within Other have also been deemed to be VIEs.
For those entities that have been deemed to be VIEs, neither MPLX nor any of its subsidiaries have been deemed to be the primary beneficiary due to voting rights on significant matters. While we have the ability to exercise influence through participation in the management committees which make all significant decisions, we have equal influence over each committee as a joint interest partner and all significant decisions require the consent of the other investors without regard to economic interest. As such, we have determined that these entities should not be consolidated and applied the equity method of accounting with respect to our investments in each entity.
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 six months ended June 30, 2023. See Note 14 for information on our Guarantees related to indebtedness of equity method investees.
4. Related Party Agreements and Transactions
MPLX engages in transactions with both MPC and certain of its equity method investments as part of its normal business; however, transactions with MPC make up the majority of MPLX’s related party transactions. Transactions with related parties are further described below.
MPLX has various long-term, fee-based commercial agreements with MPC. Under these agreements, MPLX provides transportation, gathering, terminal, fuels distribution, marketing, storage, management, operational and other services to MPC. MPC has committed to provide MPLX with minimum quarterly throughput volumes on crude oil and refined products and other fees for storage capacity; operating and management fees; as well as reimbursements for certain direct and indirect costs. MPC has also committed to provide a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation service agreement. MPLX also has a keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGLs related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity risk. Additionally, MPLX has obligations to
9
MPC for services provided to MPLX by MPC under omnibus and employee services-type agreements as well as other agreements.
During the second quarter of 2023, several terminal and storage services agreements with MPC were amended for certain items, including exercise of a five-year renewal option, with terms now extending to 2028.
Related Party Loan
MPLX is party to a loan agreement (the “MPC Loan Agreement”) with MPC. Under the terms of the MPC Loan Agreement, MPC extends loans to MPLX on a revolving basis as requested by MPLX and as agreed to by MPC. The borrowing capacity of the MPC Loan Agreement is $1.5 billion aggregate principal amount of all loans outstanding at any one time. The MPC Loan Agreement is scheduled to expire, and borrowings under the loan agreement are scheduled to mature and become due and payable on July 31, 2024, provided that MPC may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to maturity. Borrowings under the MPC Loan Agreement bear interest at one-month term SOFR adjusted upward by 0.10 percent plus 1.25 percent or such lower rate as would be applicable to such loans under the MPLX Credit Agreement as discussed in Note 11.
There was no activity on the MPC Loan Agreement for the six months ended June 30, 2023.
Related Party Revenue
Related party sales to MPC primarily consist of crude oil and refined products pipeline and trucking transportation services based on tariff or 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. Amounts earned under these agreements are classified as Other income - related parties in the Consolidated Statements of Income.
Certain product sales to MPC and other related parties net to zero within the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For the three and six months ended June 30, 2023, these sales totaled $150 million and $348 million, respectively. For the three and six months ended June 30, 2022, these sales totaled $281 million and $574 million, respectively.
Related Party Expenses
MPC charges MPLX for executive management services and certain general and administrative services provided to MPLX under the terms of our omnibus agreements (“Omnibus charges”) and for certain employee services provided to MPLX under employee services agreements (“ESA charges”). Omnibus charges and ESA charges are classified as Rental cost of sales - related parties, Purchases - related parties, or General and administrative expenses depending on the nature of the asset or activity with which the costs are associated. 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.
For the three and six months ended June 30, 2023, General and administrative expenses incurred from MPC totaled $61 million and $125 million, respectively. For the three and six months ended June 30, 2022, General and administrative expenses incurred from MPC totaled $58 million and $113 million, respectively.
Some charges incurred under the omnibus and employee service agreements are related to engineering services and are associated with assets under construction. These charges are added to Property, plant and equipment, net on the Consolidated Balance Sheets. For the three and six months ended June 30, 2023, these charges totaled $18 million and $28 million, respectively. For the three and six months ended June 30, 2022, these charges totaled $19 million and $38 million, respectively.
Related Party Assets and Liabilities
10
credits is a decrease in Current liabilities - related parties. Deficiency payments under agreements that have been classified as sales-type leases are recorded as a reduction against the corresponding lease receivable. In addition, capital projects MPLX undertakes at the request of MPC are reimbursed in cash and recognized as revenue over the remaining term of the applicable agreements or in some cases, as a contribution from MPC.
| (In millions) | June 30, 2023 | December 31, 2022 | |||||||||
| Current assets - related parties | |||||||||||
| Receivables | $ | $ | |||||||||
| Lease receivables | |||||||||||
| Prepaid | |||||||||||
| Other | |||||||||||
| Total | |||||||||||
| Noncurrent assets - related parties | |||||||||||
| Long-term lease receivables | |||||||||||
| Right of use assets | |||||||||||
| Unguaranteed residual asset | |||||||||||
| Long-term receivables | |||||||||||
| Total | |||||||||||
| Current liabilities - related parties | |||||||||||
MPC loan agreement and other payables(1) | |||||||||||
| Deferred revenue | |||||||||||
| Operating lease liabilities | |||||||||||
| Total | |||||||||||
| Long-term liabilities - related parties | |||||||||||
| Long-term operating lease liabilities | |||||||||||
| Long-term deferred revenue | |||||||||||
| Total | $ | $ | |||||||||
(1) There were no
Other Related Party Transactions
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.
5. Equity
The changes in the number of common units during the six months ended June 30, 2023 are summarized below:
| (In units) | Common Units | ||||||||||||||||||||||
| Balance at December 31, 2022 | |||||||||||||||||||||||
| Unit-based compensation awards | |||||||||||||||||||||||
| Balance at June 30, 2023 | |||||||||||||||||||||||
Unit Repurchase Program
On August 2, 2022, we announced the board authorization for the repurchase of up to an additional $1 billion of MPLX common units held by the public. This unit repurchase authorization has no expiration date. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
No units were repurchased during the three or six months ended June 30, 2023. As of June 30, 2023, we had $846 million remaining under the unit repurchase authorization.
11
Redemption of the Series B Preferred Units
On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding units of 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”). MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit.
Distributions on the Series B preferred units were 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. In accordance with these terms, MPLX made a final cash distribution of $21 million to Series B preferred unitholders on February 15, 2023 , in conjunction with the redemption.
The changes in the Series B preferred unit balance during the six months ended June 30, 2023 and June 30, 2022 are included in the Consolidated Statements of Equity within Series B preferred units.
Distributions
On July 25, 2023 , MPLX declared a cash distribution for the second quarter of 2023, totaling $776 million, or $0.775 per common unit. This distribution will be paid on August 14, 2023 to common unitholders of record on August 4, 2023 . This rate will also be received by Series A preferred unitholders.
Quarterly distributions for 2023 and 2022 are summarized below:
| (Per common unit) | 2023 | 2022 | |||||||||
| March 31, | $ | $ | |||||||||
| June 30, | |||||||||||
The allocation of total quarterly cash distributions to limited and preferred unitholders is as follows for the three and six months ended June 30, 2023 and June 30, 2022. Distributions, although earned, are not accrued until declared. 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.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Common and preferred unit distributions: | |||||||||||||||||||||||
| Common unitholders, includes common units of general partner | $ | $ | $ | $ | |||||||||||||||||||
| Series A preferred unit distributions | |||||||||||||||||||||||
Series B preferred unit distributions(1) | |||||||||||||||||||||||
| Total cash distributions declared | $ | $ | $ | $ | |||||||||||||||||||
(1) The six months ended June 30, 2023, includes the portion of the $21 million distribution paid to the Series B preferred unitholders on February 15, 2023 that was earned during the period prior to redemption.
6. Net Income Per Limited Partner Unit
During the three and six months ended June 30, 2023 and June 30, 2022, MPLX had participating securities consisting of common units, certain equity-based compensation awards, Series A preferred units, and Series B preferred units and also had dilutive potential common units consisting of certain equity-based compensation awards. Potential common units omitted from the diluted earnings per unit calculation for the three and six months ended June 30, 2023 and June 30, 2022 were less than 1
12
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Net income attributable to MPLX LP | $ | $ | $ | $ | |||||||||||||||||||
| Less: Distributions declared on Series A preferred units | |||||||||||||||||||||||
| Distributions declared on Series B preferred units | |||||||||||||||||||||||
| Limited partners’ distributions declared on MPLX common units (including common units of general partner) | |||||||||||||||||||||||
| Undistributed net gain attributable to MPLX LP | $ | $ | $ | $ | |||||||||||||||||||
| Three Months Ended June 30, 2023 | |||||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Total | ||||||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | |||||||||||||||||||||||||||||
| Distributions declared | $ | $ | $ | ||||||||||||||||||||||||||
| Undistributed net gain attributable to MPLX LP | |||||||||||||||||||||||||||||
Net income attributable to MPLX LP(1) | $ | ||||||||||||||||||||||||||||
| Weighted average units outstanding: | |||||||||||||||||||||||||||||
| Basic | |||||||||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | |||||||||||||||||||||||||||||
| Basic | $ | ||||||||||||||||||||||||||||
| Diluted | $ | ||||||||||||||||||||||||||||
(1) Allocation of net income attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the period.
| Three Months Ended June 30, 2022 | |||||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | |||||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | |||||||||||||||||||||||||||||
| Distributions declared | $ | $ | $ | $ | |||||||||||||||||||||||||
| Undistributed net gain attributable to MPLX LP | |||||||||||||||||||||||||||||
Net income attributable to MPLX LP(1) | $ | $ | $ | $ | |||||||||||||||||||||||||
| Weighted average units outstanding: | |||||||||||||||||||||||||||||
| Basic | |||||||||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | |||||||||||||||||||||||||||||
| Basic | $ | ||||||||||||||||||||||||||||
| Diluted | $ | ||||||||||||||||||||||||||||
(1) Allocation of net income attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the period.
13
| Six Months Ended June 30, 2023 | |||||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | |||||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | |||||||||||||||||||||||||||||
| Distributions declared | $ | $ | $ | $ | |||||||||||||||||||||||||
| Undistributed net gain attributable to MPLX LP | |||||||||||||||||||||||||||||
Net income attributable to MPLX LP(1) | $ | $ | |||||||||||||||||||||||||||
| Impact of redemption of Series B preferred units | ( | ( | |||||||||||||||||||||||||||
| Income available to common unitholders | $ | $ | |||||||||||||||||||||||||||
| Weighted average units outstanding: | |||||||||||||||||||||||||||||
| Basic | |||||||||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | |||||||||||||||||||||||||||||
| Basic | |||||||||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||||||||
(1) Allocation of net income attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the period.
| Six Months Ended June 30, 2022 | |||||||||||||||||||||||||||||
| (In millions, except per unit data) | Limited Partners’ Common Units | Series A Preferred Units | Series B Preferred Units | Total | |||||||||||||||||||||||||
| Basic and diluted net income attributable to MPLX LP per unit | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP: | |||||||||||||||||||||||||||||
| Distributions declared | $ | $ | $ | $ | |||||||||||||||||||||||||
| Undistributed net gain attributable to MPLX LP | |||||||||||||||||||||||||||||
Net income attributable to MPLX LP(1) | $ | $ | $ | $ | |||||||||||||||||||||||||
| Weighted average units outstanding: | |||||||||||||||||||||||||||||
| Basic | |||||||||||||||||||||||||||||
| Diluted | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP per limited partner unit: | |||||||||||||||||||||||||||||
| Basic | $ | ||||||||||||||||||||||||||||
| Diluted | $ | ||||||||||||||||||||||||||||
(1) Allocation of net income attributable to MPLX LP assumes all earnings for the period had been distributed based on the distribution priorities applicable to the period.
7. Segment Information
MPLX’s chief operating decision maker (“CODM”) is the chief executive officer of its general partner. The CODM 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 – gathers, transports, stores and distributes crude oil, refined products, other hydrocarbon-based products and renewables. Also includes the operation of refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities, and storage caverns.
•G&P – gathers, processes and transports natural gas; and transports, fractionates, stores and markets NGLs.
Our CODM evaluates the performance of our segments using Segment Adjusted EBITDA. Amounts included in net income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) interest and other financial costs; (iii) income/(loss) from equity method investments; (iv) distributions and adjustments related to equity method investments; (v) gain on sales-type leases; (vi) impairment expense; (vii) noncontrolling interests; and (viii) other adjustments, as applicable. 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
14
not tied to the operational performance of the segment. Assets by segment are not a measure used to assess the performance of the Partnership by our CODM and thus are not reported in our disclosures.
The tables below present information about revenues and other income, Segment Adjusted EBITDA, capital expenditures and investments in unconsolidated affiliates for our reportable segments:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| L&S | |||||||||||||||||||||||
| Service revenue | $ | $ | $ | $ | |||||||||||||||||||
| Rental income | |||||||||||||||||||||||
| Product related revenue | |||||||||||||||||||||||
| Sales-type lease revenue | |||||||||||||||||||||||
| Income from equity method investments | |||||||||||||||||||||||
| Other income | |||||||||||||||||||||||
Total segment revenues and other income(1) | |||||||||||||||||||||||
Segment Adjusted EBITDA(2) | |||||||||||||||||||||||
| Capital expenditures | |||||||||||||||||||||||
| Investments in unconsolidated affiliates | |||||||||||||||||||||||
| G&P | |||||||||||||||||||||||
| Service revenue | |||||||||||||||||||||||
| Rental income | |||||||||||||||||||||||
| Product related revenue | |||||||||||||||||||||||
| Sales-type lease revenue | |||||||||||||||||||||||
| Income from equity method investments | |||||||||||||||||||||||
| Other income | |||||||||||||||||||||||
Total segment revenues and other income(1) | |||||||||||||||||||||||
Segment Adjusted EBITDA(2) | |||||||||||||||||||||||
| Capital expenditures | |||||||||||||||||||||||
| Investments in unconsolidated affiliates | $ | $ | $ | $ | |||||||||||||||||||
(1) Within the total segment revenues and other income amounts presented above, third party revenues for the L&S segment were $187 million and $357 million for the three and six months ended June 30, 2023, respectively, and $158 million and $293 million for the three and six months ended June 30, 2022, respectively. Third party revenues for the G&P segment were $1,139 million and $2,305 million for the three and six months ended June 30, 2023, respectively, and $1,454 million and $2,666 million for the three and six months ended June 30, 2022, respectively.
(2) See below for the reconciliation from Segment Adjusted EBITDA to Net income.
The table below provides a reconciliation of Segment Adjusted EBITDA for reportable segments to Net income.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Reconciliation to Net income: | |||||||||||||||||||||||
| L&S Segment Adjusted EBITDA | $ | $ | $ | $ | |||||||||||||||||||
| G&P Segment Adjusted EBITDA | |||||||||||||||||||||||
| Total reportable segments | |||||||||||||||||||||||
Depreciation and amortization(1) | ( | ( | ( | ( | |||||||||||||||||||
| Interest and other financial costs | ( | ( | ( | ( | |||||||||||||||||||
| Income from equity method investments | |||||||||||||||||||||||
| Distributions/adjustments related to equity method investments | ( | ( | ( | ( | |||||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | |||||||||||||||||||||||
Other(2) | ( | ( | |||||||||||||||||||||
| Net income | $ | $ | $ | $ | |||||||||||||||||||
(1) Depreciation and amortization attributable to L&S was $140 million and $269 million for the three and six months ended June 30, 2023, respectively, and $129 million and $259 million for the three and six months ended June 30, 2022, respectively. Depreciation and amortization attributable to G&P was $170 million and $337 million for the three and six months ended June 30, 2023, respectively, and $181 million and $364 million for the three and six months ended June 30, 2022, respectively.
15
8. Property, Plant and Equipment
Property, plant and equipment with associated accumulated depreciation is shown below:
| June 30, 2023 | December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||
| (In millions) | Gross PP&E | Accumulated Depreciation | Net PP&E | Gross PP&E | Accumulated Depreciation | Net PP&E | |||||||||||||||||||||||||||||||||||
| L&S | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||
| G&P | |||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||
We capitalize interest as part of the cost of major projects during the construction period. Capitalized interest totaled $4 million and $7 million for the three and six months ended June 30, 2023, respectively, and $3 million and $5 million for the three and six months ended June 30, 2022, respectively.
9. Fair Value Measurements
Fair Values – Recurring
The following table presents the impact on the Consolidated Balance Sheets of MPLX’s financial instruments carried at fair value on a recurring basis as of June 30, 2023 and December 31, 2022 by fair value hierarchy level.
| June 30, 2023 | December 31, 2022 | ||||||||||||||||||||||
| (In millions) | Asset | Liability | Asset | Liability | |||||||||||||||||||
| Commodity contracts (Level 2) | |||||||||||||||||||||||
| Other current assets / Other current liabilities | $ | $ | $ | $ | |||||||||||||||||||
| Embedded derivatives in commodity contracts (Level 3) | |||||||||||||||||||||||
| Other current assets / Other current liabilities | |||||||||||||||||||||||
| Other noncurrent assets / Other long-term liabilities | |||||||||||||||||||||||
| Total carrying value in Consolidated Balance Sheets | $ | $ | $ | $ | |||||||||||||||||||
Level 2 instruments include over-the-counter fixed swaps to mitigate the price risk from our sales of propane. The swap valuations are based on observable inputs in the form of forward prices based on Mont Belvieu propane forward spot prices and contain no significant unobservable inputs.
Level 3 instruments relate to an embedded derivative liability for 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 $0.54 to $1.34 per gallon with a weighted average of $0.72 per gallon and (2) the probability of renewal of 100 percent for the -year renewal term of the gas purchase commitment and related keep-whole processing agreement. Increases or decreases in the fractionation spread result in an increase or decrease in the fair value of the embedded derivative liability, respectively.
16
Changes in Level 3 Fair Value Measurements
The following table is a reconciliation of the net beginning and ending balances recorded for net liabilities classified as Level 3 in the fair value hierarchy.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Beginning balance | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
Unrealized and realized gain included in Net Income(1) | |||||||||||||||||||||||
| Settlements | |||||||||||||||||||||||
| Ending balance | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||
| The amount of total gain for the period included in earnings attributable to the change in unrealized gain relating to liabilities still held at end of period | $ | $ | $ | $ | |||||||||||||||||||
(1) Gain/(loss) on derivatives embedded in commodity contracts are recorded in Purchased product costs in the Consolidated Statements of Income.
Fair Values – Reported
We believe the carrying value of our other financial instruments, including cash and cash equivalents, receivables, receivables from related parties, lease receivables, lease receivables from related parties, accounts payable, and payables to related parties, approximate fair value. MPLX’s fair value assessment incorporates a variety of considerations, including the duration of the instruments, MPC’s investment-grade credit rating, and the historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. 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 10).
The fair value of MPLX’s debt is estimated based on prices from recent trade activity and is categorized in Level 3 of the fair value hierarchy. The following table summarizes the fair value and carrying value of our third-party debt, excluding finance leases and unamortized debt issuance costs:
| June 30, 2023 | December 31, 2022 | ||||||||||||||||||||||
| (In millions) | Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||||||||
Outstanding debt(1) | $ | $ | $ | $ | |||||||||||||||||||
(1) Any amounts outstanding under the MPC Loan Agreement are not included in the table above, as the carrying value approximates fair value. This balance is reflected in Current liabilities - related parties in the Consolidated Balance Sheets.
10. Derivatives
As of June 30, 2023, MPLX had the following outstanding commodity contracts that were executed to manage the price risk associated with sales of propane during 2023:
| Derivative contracts not designated as hedging instruments | Financial Position | Notional Quantity | ||||||||||||
| Propane (gal) | Short | |||||||||||||
Embedded Derivative - MPLX has a natural gas purchase commitment embedded in a keep-whole processing agreement with a producer customer in the Southern Appalachian region expiring in December 2027. The customer has the unilateral option to extend the agreement for one -year term through December 2032. For accounting purposes, the natural gas purchase commitment and the term extending option have been aggregated into a single compound embedded derivative. The probability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may exist at the time they would elect whether to renew the contract. The changes in fair value of this compound embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend, and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of Income. For further information regarding the fair value measurement of derivative instruments, see Note 9. As of June 30, 2023 and December 31, 2022, the estimated fair value of this contract was a liability of $53 million and $61 million, respectively.
17
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 June 30, 2023 and December 31, 2022, there were no derivative assets or liabilities that were offset in the Consolidated Balance Sheets.
We make 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. The impact of MPLX’s derivative contracts not designated as hedging instruments and the location of gains and losses recognized in the Consolidated Statements of Income is summarized below:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Product sales: | |||||||||||||||||||||||
| Unrealized gain | $ | $ | $ | $ | |||||||||||||||||||
| Product sales derivative gain | |||||||||||||||||||||||
| Purchased product costs: | |||||||||||||||||||||||
| Realized loss | ( | ( | ( | ( | |||||||||||||||||||
| Unrealized gain | |||||||||||||||||||||||
| Purchased product cost derivative gain | |||||||||||||||||||||||
| Total derivative gain included in Net income | $ | $ | $ | $ | |||||||||||||||||||
11. Debt
MPLX’s outstanding borrowings consist of the following:
| (In millions) | June 30, 2023 | December 31, 2022 | |||||||||
| MPLX LP: | |||||||||||
| MPLX Credit Agreement | $ | $ | |||||||||
| Fixed rate senior notes | |||||||||||
| Consolidated subsidiaries: | |||||||||||
| MarkWest | |||||||||||
| ANDX | |||||||||||
| Finance lease obligations | |||||||||||
| Total | |||||||||||
| Unamortized debt issuance costs | ( | ( | |||||||||
| Unamortized discount | ( | ( | |||||||||
| Amounts due within one year | ( | ( | |||||||||
| Total long-term debt due after one year | $ | $ | |||||||||
Credit Agreement
MPLX’s credit agreement (the “MPLX Credit Agreement”) matures in July 2027 and, among other things, provides for a $2 billion unsecured revolving credit facility and letter of credit issuing capacity under the facility of up to $150 million. Letter of credit issuing capacity is included in, not in addition to, the $2 billion borrowing capacity. Borrowings under the MPLX Credit Agreement bear interest, at MPLX’s election, at either the Adjusted Term SOFR or the Alternate Base Rate, both as defined in the MPLX Credit Agreement, plus an applicable margin.
There was no activity on the MPLX Credit Agreement during the six months ended June 30, 2023.
Fixed Rate Senior Notes
MPLX’s senior notes, including those issued by consolidated subsidiaries, consist of various series of senior notes maturing between 2024 and 2058 with interest rates ranging from 1.750 percent to 5.650 percent. Interest on each series of notes is payable semi-annually in arrears on various dates depending on the series of the notes.
18
On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of notes, consisting of $1.1 billion principal amount of 5.00 percent senior notes due 2033 (the “2033 Senior Notes”) and $500 million principal amount of 5.65 percent senior notes due 2053 (the “2053 Senior Notes”). The 2033 Senior Notes were offered at a price to the public of 99.170 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023. The 2053 Senior Notes were offered at a price to the public of 99.536 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023.
On February 15, 2023, MPLX used $600 million of the net proceeds from the offering of the 2033 Senior Notes and 2053 Senior Notes described above to redeem all of the outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and cash on hand, to redeem all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest. The redemption resulted in a loss of $9 million due to the immediate expense recognition of unamortized debt discount and issuance costs for the three months ended March 31, 2023, which is included on the Consolidated Statements of Income as Other financial costs.
12. Revenue
Disaggregation of Revenue
The following tables represent a disaggregation of revenue for each reportable segment for the three and six months ended June 30, 2023 and June 30, 2022:
| Three Months Ended June 30, 2023 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | $ | $ | ||||||||||||||
| Service revenue - related parties | |||||||||||||||||
| Service revenue - product related | — | ||||||||||||||||
| Product sales | — | ||||||||||||||||
| Product sales - related parties | |||||||||||||||||
| Total revenues from contracts with customers | $ | $ | |||||||||||||||
Non-ASC 606 revenue(1) | |||||||||||||||||
| Total revenues and other income | $ | ||||||||||||||||
| Three Months Ended June 30, 2022 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | $ | $ | ||||||||||||||
| Service revenue - related parties | |||||||||||||||||
| Service revenue - product related | — | ||||||||||||||||
| Product sales | |||||||||||||||||
| Product sales - related parties | |||||||||||||||||
| Total revenues from contracts with customers | $ | $ | |||||||||||||||
Non-ASC 606 revenue(1) | |||||||||||||||||
| Total revenues and other income | $ | ||||||||||||||||
| Six Months Ended June 30, 2023 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | ||||||||||||||||
| Service revenue - related parties | |||||||||||||||||
| Service revenue - product related | — | ||||||||||||||||
| Product sales | |||||||||||||||||
| Product sales - related parties | |||||||||||||||||
| Total revenues from contracts with customers | $ | $ | |||||||||||||||
Non-ASC 606 revenue(1) | |||||||||||||||||
| Total revenues and other income | $ | ||||||||||||||||
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| Six Months Ended June 30, 2022 | |||||||||||||||||
| (In millions) | L&S | G&P | Total | ||||||||||||||
| Revenues and other income: | |||||||||||||||||
| Service revenue | $ | ||||||||||||||||
| Service revenue - related parties | |||||||||||||||||
| Service revenue - product related | |||||||||||||||||
| Product sales | |||||||||||||||||
| Product sales - related parties | |||||||||||||||||
| Total revenues from contracts with customers | $ | $ | |||||||||||||||
Non-ASC 606 revenue(1) | |||||||||||||||||
| Total revenues and other income | $ | ||||||||||||||||
Contract Balances
Our receivables are primarily associated with customer contracts. Payment terms vary by product or service type, however the period between invoicing and payment is not significant. Included within the receivables are balances related to commodity sales on behalf of our producer customers, for which we remit the net sales price back to the producer customers upon completion of the sale. These balances are included in Receivables, net on the Consolidated Balance Sheets.
Under certain of our contracts, we recognize revenues in excess of billings which we present as contract assets. Contract assets typically relate to deficiency payments related to minimum volume commitments and aid in construction agreements where the revenue recognized and MPLX’s rights to consideration for work completed exceeds the amount billed to the customer. Contract assets are included in Other current assets and Other noncurrent assets on the Consolidated Balance Sheets.
Under certain of our contracts, we receive payments in advance of satisfying our performance obligations, which are recorded as contract liabilities. Contract liabilities, which we present 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.
The tables below reflect the changes in ASC 606 contract balances for the six-month periods ended June 30, 2023 and June 30, 2022:
| (In millions) | Balance at December 31, 2022 | Additions/ (Deletions) | Revenue Recognized(1) | Balance at June 30, 2023 | |||||||||||||||||||
| Contract assets | $ | $ | ( | $ | $ | ||||||||||||||||||
| Long-term contract assets | |||||||||||||||||||||||
| Deferred revenue | ( | ||||||||||||||||||||||
| Deferred revenue - related parties | ( | ||||||||||||||||||||||
| Long-term deferred revenue | |||||||||||||||||||||||
| Long-term deferred revenue - related parties | |||||||||||||||||||||||
| Contract liabilities | |||||||||||||||||||||||
| Long-term contract liabilities | $ | $ | ( | $ | $ | ||||||||||||||||||
| (In millions) | Balance at December 31, 2021 | Additions/ (Deletions) | Revenue Recognized(1) | Balance at June 30, 2022 | |||||||||||||||||||
| Contract assets | $ | $ | ( | $ | $ | ||||||||||||||||||
| Long-term contract assets | |||||||||||||||||||||||
| Deferred revenue | ( | ||||||||||||||||||||||
| Deferred revenue - related parties | ( | ||||||||||||||||||||||
| Long-term deferred revenue | |||||||||||||||||||||||
| Long-term deferred revenue - related parties | ( | ||||||||||||||||||||||
| Long-term contract liabilities | $ | $ | $ | $ | |||||||||||||||||||
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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) as of June 30, 2023. The amounts presented below are generally limited to fixed consideration from contracts with customers that contain minimum volume commitments.
A significant portion of our future contracted revenue is excluded from the amounts presented below in accordance with ASC 606. Variable consideration that is constrained or not required to be estimated as it reflects our efforts to perform is excluded from this disclosure. Additionally, we do not disclose information on the future performance obligations for any contract with an original expected duration of one year or less, or that are terminable by our customer with little or no termination penalties. Potential future performance obligations related to renewals that have not yet been exercised or are not certain of exercise are excluded from the amounts presented below. Revenues classified as Rental income and Sales-type lease revenue are also excluded from this table.
| (In billions) | |||||
| 2023 | $ | ||||
| 2024 | |||||
| 2025 | |||||
| 2026 | |||||
| 2027 | |||||
| Thereafter | |||||
| Total estimated revenue on remaining performance obligations | $ | ||||
As of June 30, 2023, unsatisfied performance obligations included in the Consolidated Balance Sheets are $402 million and will be recognized as revenue as the obligations are satisfied, which is expected to occur over the next 21 years. A portion of this amount is not disclosed in the table above as it is deemed variable consideration due to volume variability.
13. Supplemental Cash Flow Information
| Six Months Ended June 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Net cash provided by operating activities included: | |||||||||||
| Interest paid (net of amounts capitalized) | $ | $ | |||||||||
| Income taxes paid | |||||||||||
| Non-cash investing and financing activities: | |||||||||||
| Net transfers of property, plant and equipment (to)/from materials and supplies inventories | |||||||||||
| Net transfers of property, plant and equipment to lease receivable | $ | $ | |||||||||
The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that do not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:
| Six Months Ended June 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Additions to property, plant and equipment | $ | $ | |||||||||
| Increase in capital accruals | |||||||||||
| Total capital expenditures | $ | $ | |||||||||
14. Commitments and Contingencies
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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.
Accrued liabilities for remediation totaled $ at both June 30, 2023 and December 31, 2022. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, that may be imposed.
MPLX is involved in environmental enforcement matters arising in the ordinary course of business. While the outcome and impact to MPLX cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its consolidated results of operations, financial position or cash flows.
Other Legal Proceedings
In July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the Bureau of Indian Affairs (“BIA”) relating to a portion of the Tesoro High Plains Pipeline that crosses the Fort Berthold Reservation in North Dakota. The notification demanded the immediate cessation of pipeline operations and assessed trespass damages of approximately $187 million. After subsequent appeal proceedings and in compliance with a new order issued by the BIA, in December 2020, THPP paid approximately $4 million in assessed trespass damages and ceased use of the portion of the pipeline that crosses the property at issue. In March 2021, the BIA issued an order purporting to vacate the BIA's prior orders related to THPP’s alleged trespass and direct the Regional Director of the BIA to reconsider the issue of THPP’s alleged trespass and issue a new order. In April 2021, THPP filed a lawsuit in the District of North Dakota against the United States of America, the U.S. Department of the Interior and the BIA (together, the “U.S. Government Parties”) challenging the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the U.S. Government Parties filed their answer and counterclaims to THPP’s suit claiming THPP is in continued trespass with respect to the pipeline and seek disgorgement of pipeline profits from June 1, 2013 to present, removal of the pipeline and remediation. We intend to vigorously defend ourselves against these counterclaims.
MPLX is also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to MPLX cannot be predicted with certainty, management believes the resolution of these other lawsuits and proceedings will not, individually or collectively, have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Guarantees related to indebtedness of equity method investees
We hold a 9.19 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 or DAPL. In 2020, the U.S. District Court for the District of Columbia (the “D.D.C.”) ordered the U.S. Army Corps of Engineers (“Army Corps”), which granted permits and an easement for the Bakken Pipeline system, to prepare an environmental impact statement (“EIS”) relating to an easement under Lake Oahe in North Dakota. The D.D.C. later vacated the easement. The EIS has been delayed and the Army Corps currently expects to release a draft EIS in 2023.
In May 2021, the D.D.C. denied a renewed request for an injunction to shut down the pipeline while the EIS is being prepared. In June 2021, the D.D.C. issued an order dismissing without prejudice the tribes’ claims against the Dakota Access Pipeline. The litigation could be reopened or new litigation challenging the EIS, once completed, could be filed. The pipeline remains operational.
We have entered into a Contingent Equity Contribution Agreement whereby MPLX LP, along with the other joint venture owners in the Bakken Pipeline system, has agreed to make equity contributions to the joint venture upon certain events occurring to allow the entities that own and operate the Bakken Pipeline system to satisfy their senior note payment obligations. The senior notes were issued to repay amounts owed by the pipeline companies to fund the cost of construction of the Bakken Pipeline system.
If the pipeline were temporarily shut down, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and any portion of the principal that matures while the pipeline is shutdown. MPLX also expects to contribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the permit and/or return the pipeline into operation. If the vacatur of the easement permit results in a permanent shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of the cost to redeem the bonds (including the one percent redemption premium required pursuant to the indenture governing the notes) and any accrued and unpaid interest. As of June 30, 2023, our maximum potential undiscounted payments under the Contingent Equity Contribution Agreement were approximately $170 million.
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Contractual Commitments and Contingencies
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 June 30, 2023, 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.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations should also be read in conjunction with the unaudited consolidated financial statements and accompanying footnotes included under Item 1. Financial Statements and in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2022.
Disclosures Regarding Forward-Looking Statements
This Quarterly Report on Form 10-Q, particularly Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements that are subject to risks, contingencies or uncertainties. You can identify forward-looking statements by words such as “anticipate,” “believe,” “commitment,” “could,” “design,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “project,” “prospective,” “pursue,” “seek,” “should,” “strategy,” “target,” “will,” “would” or other similar expressions that convey the uncertainty of future events or outcomes.
Forward-looking statements include, among other things, statements regarding:
•future financial and operating results;
•environmental, social and governance (“ESG”) plans and goals, including those related to greenhouse gas emissions, diversity and inclusion and ESG reporting;
•future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;
•the success or timing of completion of ongoing or anticipated capital or maintenance projects;
•business strategies, growth opportunities and expected investments;
•the timing and amount of future distributions or unit repurchases; and
•the anticipated effects of actions of third parties such as competitors, activist investors, federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.
Our forward-looking statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. Forward-looking and other statements regarding our ESG plans and goals are not an indication that these statements are material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current, and forward-looking ESG-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future. Material differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:
•general economic, political or regulatory developments, including inflation, interest rates, changes in governmental policies relating to refined petroleum products, crude oil, natural gas, NGLs, renewables, or taxation;
•the ability of MPC to achieve its strategic objectives and the effects of those strategic decisions on us;
•further impairments;
•negative capital market conditions, including an increase of the current yield on common units;
•the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;
•the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, and the effects of any such divestitures on our business, financial condition, results of operations and cash flows;
•the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models;
•the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products, or renewables;
•volatility in or degradation of general economic, market, industry or business conditions as a result of the COVID-19 pandemic, other infectious disease outbreaks, natural hazards, extreme weather events, the military conflict between Russia and Ukraine, other conflicts, inflation, rising interest rates or otherwise;
•changes to the expected construction costs and timing of projects and planned investments, and the ability to obtain regulatory and other approvals with respect thereto;
•completion of midstream infrastructure by competitors;
•disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;
•the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;
•modifications to financial policies, capital budgets, and earnings and distributions;
•the ability to manage disruptions in credit markets or changes to credit ratings;
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•compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;
•adverse results in litigation;
•the effect of restructuring or reorganization of business components;
•the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;
•foreign imports and exports of crude oil, refined products, natural gas and NGLs;
•changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products, other hydrocarbon-based products, or renewables;
•changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks, refined products, or renewables;
•the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
•actions taken by our competitors, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities in response to market conditions;
•expectations regarding joint venture arrangements and other acquisitions or divestitures of assets;
•midstream and refining industry overcapacity or undercapacity;
•accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, means of transportation, or those of our suppliers or customers;
•acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or transport crude oil, natural gas, NGLs, refined products, or renewables;
•political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs, other hydrocarbon-based products, or renewables;
•the imposition of windfall profit taxes or maximum refining margin penalties on companies operating in the energy industry in California or other jurisdictions; and
•our ability to successfully achieve our ESG goals and targets within the expected timeframe, if at all.
For additional risk factors affecting our business, see the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2022. We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.
MPLX Overview
We are a diversified, large-cap master limited partnership formed by MPC in 2012 that owns and operates midstream energy infrastructure and logistics assets, and provides fuels distribution services. The business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). The L&S segment primarily engages in the gathering, transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and renewables. The L&S segment also includes the operation of our refining logistics, fuels distribution and inland marine businesses, terminals, rail facilities and storage caverns. The G&P segment provides gathering, processing and transportation of natural gas as well as the transportation, fractionation, storage and marketing of NGLs.
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Significant Financial and Other Highlights
Significant financial highlights for the three months ended June 30, 2023 and June 30, 2022 are shown in the chart below. Refer to the Results of Operations, the Liquidity and Capital Resources, and Non-GAAP Financial Information sections for further information.
(1) Non-GAAP measure. See reconciliations that follow for the most directly comparable GAAP measures.
Other Highlights
•Returned $799 million and $1,620 million of capital to unitholders in the three and six months ended June 30, 2023, in the form of distributions.
•Announced a second quarter 2023 distribution of $0.7750 per common unit.
Current Economic Environment
In an effort to ease inflation in support of its monetary policy goals, the Federal Reserve has raised interest rates multiple times throughout 2022 and 2023. We cannot predict the effect of higher interest rates, the concern of a recession, or the impact of inflation and fuel prices on demand for our services. In response to this business environment, MPLX remains focused on executing its strategic priorities of strict capital discipline, fostering a low-cost culture, and portfolio optimization. Also, to the extent permitted by regulations and our existing agreements, many of which provide for inflation-based adjustments, we have increased the fees we charge our customers to reflect higher levels of inflation.
Non-GAAP Financial Information
Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA, DCF, adjusted free cash flow (“Adjusted FCF”), and Adjusted FCF after distributions. 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) provision for income taxes; (ii) interest and other financial costs; (iii) depreciation and amortization; (iv) income/(loss) from equity method investments; (v) distributions and adjustments related to equity method investments; (vi) gain on sales-type leases; (vii) impairment expense; (viii) noncontrolling interests; and (ix) other adjustments, as applicable. We also use DCF, which we define as Adjusted EBITDA adjusted for: (i) deferred revenue impacts; (ii) sales-type lease payments, net of income; (iii) net interest and other financial costs; (iv) net maintenance capital expenditures; (v) equity method investment capital expenditures paid out; and (vi) other adjustments as deemed necessary.
We define Adjusted FCF as net cash provided by operating activities adjusted for: (i) net cash used in investing activities; (ii) cash contributions from MPC; and (iii) cash distributions to noncontrolling interests. We define Adjusted FCF after distributions as Adjusted FCF less base distributions to common and preferred unitholders.
We believe that the presentation of Adjusted EBITDA, DCF, Adjusted FCF and Adjusted FCF after distributions provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities while the GAAP measure
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most directly comparable to Adjusted FCF and Adjusted FCF after distributions is net cash provided by operating activities. These non-GAAP financial measures should not be considered alternatives to GAAP net income or net cash provided by operating activities as they have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. These non-GAAP financial measures should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because non-GAAP financial measures may be defined differently by other companies in our industry, our definitions may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Results of Operations. For a reconciliation of Adjusted FCF and Adjusted FCF after distributions to their most directly comparable measure calculated and presented in accordance with GAAP, see Liquidity and Capital Resources.
Comparability of our Financial Results
During the normal course of business, we amend or modify our contractual agreements with customers. These amendments or modifications require the agreements to be reassessed under ASU No. 2016-02, Leases (“ASC 842”), which can impact the classification of revenues or costs associated with the agreement. These reassessments may impact the comparability of our financial results.
Results of Operations
The following tables and discussion summarize our results of operations, including a reconciliation of Adjusted EBITDA and DCF from Net income and Net cash provided by operating activities, to the most directly comparable GAAP financial measures. This discussion should be read in conjunction with Item 1. Financial Statements and is intended to provide investors with a reasonable basis for assessing our historical operations, but should not serve as the only criteria for predicting our future performance.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | |||||||||||||||||||||||||||||
| Revenues and other income: | |||||||||||||||||||||||||||||||||||
| Total revenues and other income | $ | 2,690 | $ | 2,940 | $ | (250) | $ | 5,403 | $ | 5,550 | $ | (147) | |||||||||||||||||||||||
| Costs and expenses: | |||||||||||||||||||||||||||||||||||
| Cost of revenues (excludes items below) | 348 | 323 | 25 | 656 | 610 | 46 | |||||||||||||||||||||||||||||
| Purchased product costs | 354 | 663 | (309) | 760 | 1,130 | (370) | |||||||||||||||||||||||||||||
| Rental cost of sales | 20 | 42 | (22) | 40 | 79 | (39) | |||||||||||||||||||||||||||||
| Rental cost of sales - related parties | 9 | 19 | (10) | 16 | 34 | (18) | |||||||||||||||||||||||||||||
| Purchases - related parties | 357 | 351 | 6 | 718 | 670 | 48 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 310 | 310 | — | 606 | 623 | (17) | |||||||||||||||||||||||||||||
| General and administrative expenses | 89 | 82 | 7 | 178 | 160 | 18 | |||||||||||||||||||||||||||||
| Other taxes | 28 | 33 | (5) | 58 | 67 | (9) | |||||||||||||||||||||||||||||
| Total costs and expenses | 1,515 | 1,823 | (308) | 3,032 | 3,373 | (341) | |||||||||||||||||||||||||||||
| Income from operations | 1,175 | 1,117 | 58 | 2,371 | 2,177 | 194 | |||||||||||||||||||||||||||||
| Related-party interest and other financial costs | — | 1 | (1) | — | 5 | (5) | |||||||||||||||||||||||||||||
| Interest expense, net of amounts capitalized | 226 | 212 | 14 | 450 | 410 | 40 | |||||||||||||||||||||||||||||
| Other financial costs | 7 | 20 | (13) | 26 | 40 | (14) | |||||||||||||||||||||||||||||
| Income before income taxes | 942 | 884 | 58 | 1,895 | 1,722 | 173 | |||||||||||||||||||||||||||||
| Provision for income taxes | — | — | — | 1 | 5 | (4) | |||||||||||||||||||||||||||||
| Net income | 942 | 884 | 58 | 1,894 | 1,717 | 177 | |||||||||||||||||||||||||||||
| Less: Net income attributable to noncontrolling interests | 9 | 9 | — | 18 | 17 | 1 | |||||||||||||||||||||||||||||
| Net income attributable to MPLX LP | 933 | 875 | 58 | 1,876 | 1,700 | 176 | |||||||||||||||||||||||||||||
Adjusted EBITDA attributable to MPLX LP(1) | 1,531 | 1,457 | 74 | 3,050 | 2,850 | 200 | |||||||||||||||||||||||||||||
DCF attributable to MPLX(1) | $ | 1,315 | $ | 1,237 | $ | 78 | $ | 2,583 | $ | 2,447 | $ | 136 | |||||||||||||||||||||||
(1) Non-GAAP measure. See reconciliation below to the most directly comparable GAAP measures.
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| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | |||||||||||||||||||||||||||||
| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income: | |||||||||||||||||||||||||||||||||||
| Net income | $ | 942 | $ | 884 | $ | 58 | $ | 1,894 | $ | 1,717 | $ | 177 | |||||||||||||||||||||||
| Provision for income taxes | — | — | — | 1 | 5 | (4) | |||||||||||||||||||||||||||||
| Interest and other financial costs | 233 | 233 | — | 476 | 455 | 21 | |||||||||||||||||||||||||||||
| Income from operations | 1,175 | 1,117 | 58 | 2,371 | 2,177 | 194 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 310 | 310 | — | 606 | 623 | (17) | |||||||||||||||||||||||||||||
| Income from equity method investments | (145) | (111) | (34) | (279) | (210) | (69) | |||||||||||||||||||||||||||||
| Distributions/adjustments related to equity method investments | 190 | 152 | 38 | 343 | 284 | 59 | |||||||||||||||||||||||||||||
Other(1) | 11 | (1) | 12 | 29 | (5) | 34 | |||||||||||||||||||||||||||||
| Adjusted EBITDA | 1,541 | 1,467 | 74 | 3,070 | 2,869 | 201 | |||||||||||||||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | (10) | (10) | — | (20) | (19) | (1) | |||||||||||||||||||||||||||||
| Adjusted EBITDA attributable to MPLX LP | 1,531 | 1,457 | 74 | 3,050 | 2,850 | 200 | |||||||||||||||||||||||||||||
| Deferred revenue impacts | 28 | 24 | 4 | 40 | 48 | (8) | |||||||||||||||||||||||||||||
| Sales-type lease payments, net of income | 2 | 5 | (3) | 6 | 10 | (4) | |||||||||||||||||||||||||||||
Net interest and other financial costs(2) | (221) | (215) | (6) | (438) | (419) | (19) | |||||||||||||||||||||||||||||
| Maintenance capital expenditures, net of reimbursements | (21) | (39) | 18 | (65) | (53) | (12) | |||||||||||||||||||||||||||||
| Equity method investment maintenance capital expenditures paid out | (2) | (3) | 1 | (7) | (6) | (1) | |||||||||||||||||||||||||||||
| Other | (2) | 8 | (10) | (3) | 17 | (20) | |||||||||||||||||||||||||||||
| DCF attributable to MPLX LP | 1,315 | 1,237 | 78 | 2,583 | 2,447 | 136 | |||||||||||||||||||||||||||||
| Preferred unit distributions | (23) | (31) | 8 | (51) | (63) | 12 | |||||||||||||||||||||||||||||
| DCF attributable to GP and LP unitholders | $ | 1,292 | $ | 1,206 | $ | 86 | $ | 2,532 | $ | 2,384 | $ | 148 | |||||||||||||||||||||||
(1) Includes unrealized derivative gain/(loss), non-cash equity-based compensation and other miscellaneous items.
(2) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.
28
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | |||||||||||||||||||||||||||||
| Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities: | |||||||||||||||||||||||||||||||||||
| Net cash provided by operating activities | $ | 1,437 | $ | 1,487 | $ | (50) | $ | 2,664 | $ | 2,612 | $ | 52 | |||||||||||||||||||||||
| Changes in working capital items | (160) | (266) | 106 | (112) | (148) | 36 | |||||||||||||||||||||||||||||
| All other, net | 6 | 9 | (3) | (3) | (36) | 33 | |||||||||||||||||||||||||||||
| Loss on extinguishment of debt | — | — | — | 9 | — | 9 | |||||||||||||||||||||||||||||
Net interest and other financial costs(1) | 221 | 215 | 6 | 438 | 419 | 19 | |||||||||||||||||||||||||||||
| Other adjustments to equity method investment distributions | (1) | 14 | (15) | 12 | 26 | (14) | |||||||||||||||||||||||||||||
| Other | 38 | 8 | 30 | 62 | (4) | 66 | |||||||||||||||||||||||||||||
| Adjusted EBITDA | 1,541 | 1,467 | 74 | 3,070 | 2,869 | 201 | |||||||||||||||||||||||||||||
| Adjusted EBITDA attributable to noncontrolling interests | (10) | (10) | — | (20) | (19) | (1) | |||||||||||||||||||||||||||||
| Adjusted EBITDA attributable to MPLX LP | 1,531 | 1,457 | 74 | 3,050 | 2,850 | 200 | |||||||||||||||||||||||||||||
| Deferred revenue impacts | 28 | 24 | 4 | 40 | 48 | (8) | |||||||||||||||||||||||||||||
| Sales-type lease payments, net of income | 2 | 5 | (3) | 6 | 10 | (4) | |||||||||||||||||||||||||||||
Net interest and other financial costs(1) | (221) | (215) | (6) | (438) | (419) | (19) | |||||||||||||||||||||||||||||
| Maintenance capital expenditures, net of reimbursements | (21) | (39) | 18 | (65) | (53) | (12) | |||||||||||||||||||||||||||||
| Equity method investment maintenance capital expenditures paid out | (2) | (3) | 1 | (7) | (6) | (1) | |||||||||||||||||||||||||||||
| Other | (2) | 8 | (10) | (3) | 17 | (20) | |||||||||||||||||||||||||||||
| DCF attributable to MPLX LP | 1,315 | 1,237 | 78 | 2,583 | 2,447 | 136 | |||||||||||||||||||||||||||||
| Preferred unit distributions | (23) | (31) | 8 | (51) | (63) | 12 | |||||||||||||||||||||||||||||
| DCF attributable to GP and LP unitholders | $ | 1,292 | $ | 1,206 | $ | 86 | $ | 2,532 | $ | 2,384 | $ | 148 | |||||||||||||||||||||||
(1) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs.
Three months ended June 30, 2023 compared to three months ended June 30, 2022
Total revenues and other income decreased $250 million in the second quarter of 2023 compared to the same period of 2022. The decrease was driven by lower product sales revenue as a result of lower NGL prices during the second quarter of 2023 as compared to the same period of 2022. The decrease was partially offset by higher throughput and rate escalations across the business and a $34 million increase in income from equity method investments primarily due to higher throughput.
Cost of revenues increased $25 million and rental cost of sales (including related party) decreased $32 million in the second quarter of 2023 compared to the same period of 2022. These offsetting variances reflect the modification of a gathering and compression agreement in the third quarter of 2022 (“Third-Party Lease Modification”) which resulted in a change in the presentation of expenses from rental cost of sales to cost of revenues.
Purchased product costs decreased $309 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $393 million, partially offset by higher volumes of $90 million.
Interest expense, net of amounts capitalized increased $14 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to refinancing maturing debt with fixed rate debt at higher interest rates in 2022 and 2023 in addition to taking on incremental debt in order to finance the redemption of the Series B preferred units in the first quarter of 2023. Other financial costs also benefited from higher interest earned during the second quarter of 2023. Refer to the Liquidity and Capital Resources section for further information.
Six months ended June 30, 2023 compared to six months ended June 30, 2022
Total revenues and other income decreased $147 million in the first six months of 2023 compared to the same period of 2022. The decrease was driven by lower product sales revenue as a result of lower NGL prices during the first six months of 2023 as compared to the same period of 2022. The decrease was partially offset by higher throughput and rate escalations across the business and a $69 million increase in income from equity method investments primarily due to higher throughput.
29
Cost of revenues increased $46 million and rental cost of sales (including related party) decreased $57 million in the first six months of 2023 compared to the same period of 2022. These offsetting variances reflect the modification of a gathering and compression agreement in the third quarter of 2022 (“Third-Party Lease Modification”) which resulted in a change in the presentation of expenses from rental cost of sales to cost of revenues.
Purchased product costs decreased $370 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $550 million, partially offset by higher volumes of $172 million.
Purchases - related parties increased $48 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to higher related-party purchased product costs and higher transportation costs.
Depreciation and amortization decreased $17 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to lower depreciation as a result of the derecognition of fixed assets in connection with the Third-Party Lease Modification in the third quarter of 2022. This decrease was partially offset by depreciation on new assets placed in service after the second quarter of 2022 and accelerated depreciation related to idled assets.
General and administrative expenses increased $18 million in the first six months of 2023 compared to the same period of 2022 due to increased costs from MPC, primarily higher employee costs.
Interest expense, net of amounts capitalized increased $40 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to refinancing debt with fixed rate debt at higher interest rates in 2022 and 2023 in addition to taking on incremental debt in order to finance the redemption of the Series B preferred units in the first quarter of 2023. Other financial costs also benefited from higher interest earned during 2023. Refer to the Liquidity and Capital Resources section for further information.
30
Segment Results
We classify our business in the following reportable segments: L&S and G&P. We evaluate the performance of our segments using Segment Adjusted EBITDA. 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) interest and other financial costs; (iii) income/(loss) from equity method investments; (iv) distributions and adjustments related to equity method investments; (v) gain on sales-type leases; (vi) impairment expense; (vii) noncontrolling interests; and (viii) other adjustments, as applicable. 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 three and six months ended June 30, 2023 and June 30, 2022.
L&S Segment
Second Quarter L&S Segment Financial Highlights (in millions)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | |||||||||||||||||||||||||||||
| Service revenue | $ | 1,060 | $ | 1,010 | $ | 50 | $ | 2,093 | $ | 1,993 | $ | 100 | |||||||||||||||||||||||
| Rental income | 210 | 208 | 2 | 422 | 383 | 39 | |||||||||||||||||||||||||||||
| Product related revenue | 3 | 7 | (4) | 8 | 11 | (3) | |||||||||||||||||||||||||||||
| Sales-type lease revenue | 125 | 114 | 11 | 250 | 225 | 25 | |||||||||||||||||||||||||||||
| Income from equity method investments | 82 | 59 | 23 | 153 | 111 | 42 | |||||||||||||||||||||||||||||
| Other income | 18 | 22 | (4) | 32 | 34 | (2) | |||||||||||||||||||||||||||||
| Total segment revenues and other income | 1,498 | 1,420 | 78 | 2,958 | 2,757 | 201 | |||||||||||||||||||||||||||||
| Cost of revenues | 158 | 159 | (1) | 293 | 300 | (7) | |||||||||||||||||||||||||||||
| Purchases - related parties | 263 | 258 | 5 | 507 | 497 | 10 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 140 | 129 | 11 | 269 | 259 | 10 | |||||||||||||||||||||||||||||
| General and administrative expenses | 51 | 43 | 8 | 100 | 86 | 14 | |||||||||||||||||||||||||||||
| Other taxes | 20 | 20 | — | 39 | 41 | (2) | |||||||||||||||||||||||||||||
| Total costs and expenses | 632 | 609 | 23 | 1,208 | 1,183 | 25 | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | 1,022 | 966 | 56 | 2,048 | 1,870 | 178 | |||||||||||||||||||||||||||||
| Capital expenditures | 110 | 81 | 29 | 178 | 158 | 20 | |||||||||||||||||||||||||||||
Investments in unconsolidated affiliates(1) | $ | 1 | $ | 10 | $ | (9) | $ | 16 | $ | 78 | $ | (62) | |||||||||||||||||||||||
(1) The six months ended June 30, 2022 includes a contribution of $60 million to our Bakken Pipeline joint venture to fund our share of a debt repayment by the joint venture.
Three months ended June 30, 2023 compared to three months ended June 30, 2022
Service revenue increased $50 million in the second quarter of 2023 compared to the same period of 2022. This was primarily driven by higher pipeline tariff rates, increased pipeline throughput, and $12 million from refining logistics fee escalations. The increase was partially offset by a decrease of $8 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue as a result of modifications to agreements with MPC.
Sales-type lease revenue increased $11 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to an increase of $7 million from changes in the presentation of revenue between service revenue, rental income
31
and sales-type lease revenue as a result of modifications to agreements with MPC, as well as from $3 million from refining logistics due to fee escalations.
Income from equity method investments increased $23 million in the second quarter of 2023 compared to the same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.
Six months ended June 30, 2023 compared to six months ended June 30, 2022
Service revenue increased $100 million in the first six months of 2023 compared to the same period of 2022. This was primarily driven by higher pipeline tariff rates, increased pipeline throughput, and $17 million from refining logistics fee escalations. These increases were partially offset by a decrease of $39 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue driven by modifications to agreements with MPC.
Rental income increased $39 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to an increase of $21 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue driven by modifications to agreements with MPC. There was also increased revenue of $13 million from refining logistics primarily due to fee escalations.
Sales-type lease revenue increased $25 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to an increase of $18 million from changes in the presentation of revenue between service revenue, rental income and sales-type lease revenue as a result of modifications to agreements with MPC, as well as an increase of $7 million from refining logistics due to fee escalations.
Income from equity method investments increased $42 million in the first six months of 2023 compared to the same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.
General and administrative expenses increased $14 million in the first six months of 2023 compared to the same period of 2022, due to increased costs from MPC, primarily higher employee costs.
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L&S Operating Data
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| L&S | |||||||||||||||||||||||
| Pipeline throughput (mbpd) | |||||||||||||||||||||||
| Crude oil pipelines | 3,834 | 3,674 | 3,739 | 3,527 | |||||||||||||||||||
| Product pipelines | 2,118 | 2,247 | 2,053 | 2,103 | |||||||||||||||||||
| Total pipelines | 5,952 | 5,921 | 5,792 | 5,630 | |||||||||||||||||||
Average tariff rates ($ per barrel)(1) | |||||||||||||||||||||||
| Crude oil pipelines | $ | 0.93 | $ | 0.86 | $ | 0.93 | $ | 0.89 | |||||||||||||||
| Product pipelines | 0.81 | 0.77 | 0.83 | 0.80 | |||||||||||||||||||
| Total pipelines | $ | 0.89 | $ | 0.82 | $ | 0.89 | $ | 0.85 | |||||||||||||||
| Terminal throughput (mbpd) | 3,180 | 3,101 | 3,136 | 3,021 | |||||||||||||||||||
Marine Assets (number in operation)(2) | |||||||||||||||||||||||
| Barges | 307 | 296 | 307 | 296 | |||||||||||||||||||
| Towboats | 27 | 23 | 27 | 23 | |||||||||||||||||||
(1) Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels. Transportation revenues include tariff and other fees, which may vary by region and nature of services provided.
(2) Represents total at end of period.
33
G&P Segment
Second Quarter G&P Segment Financial Highlights (in millions)
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | Variance | 2023 | 2022 | Variance | |||||||||||||||||||||||||||||
| Service revenue | $ | 546 | $ | 505 | $ | 41 | $ | 1,071 | $ | 991 | $ | 80 | |||||||||||||||||||||||
| Rental income | 52 | 92 | (40) | 103 | 173 | (70) | |||||||||||||||||||||||||||||
| Product related revenue | 467 | 860 | (393) | 1,031 | 1,521 | (490) | |||||||||||||||||||||||||||||
| Sales-type lease revenue | 33 | — | 33 | 67 | — | 67 | |||||||||||||||||||||||||||||
| Income from equity method investments | 63 | 52 | 11 | 126 | 99 | 27 | |||||||||||||||||||||||||||||
| Other income | 31 | 11 | 20 | 47 | 9 | 38 | |||||||||||||||||||||||||||||
| Total segment revenues and other income | 1,192 | 1,520 | (328) | 2,445 | 2,793 | (348) | |||||||||||||||||||||||||||||
| Cost of revenues | 219 | 225 | (6) | 419 | 423 | (4) | |||||||||||||||||||||||||||||
| Purchased product costs | 354 | 663 | (309) | 760 | 1,130 | (370) | |||||||||||||||||||||||||||||
| Purchases - related parties | 94 | 93 | 1 | 211 | 173 | 38 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 170 | 181 | (11) | 337 | 364 | (27) | |||||||||||||||||||||||||||||
| General and administrative expenses | 38 | 39 | (1) | 78 | 74 | 4 | |||||||||||||||||||||||||||||
| Other taxes | 8 | 13 | (5) | 19 | 26 | (7) | |||||||||||||||||||||||||||||
| Total costs and expenses | 883 | 1,214 | (331) | 1,824 | 2,190 | (366) | |||||||||||||||||||||||||||||
| Segment Adjusted EBITDA | 509 | 491 | 18 | 1,002 | 980 | 22 | |||||||||||||||||||||||||||||
| Capital expenditures | 143 | 95 | 48 | 266 | 190 | 76 | |||||||||||||||||||||||||||||
| Investments in unconsolidated affiliates | $ | 25 | $ | 36 | $ | (11) | $ | 61 | $ | 78 | $ | (17) | |||||||||||||||||||||||
Three months ended June 30, 2023 compared to three months ended June 30, 2022
Service revenue increased $41 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to higher volumes and higher throughput fee rates in the Marcellus and Rockies.
Rental income decreased $40 million and sales-type lease revenue increased $33 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to changes in the presentation of revenue between rental income and sales-type lease revenue as a result of the Third-Party Lease Modification in the third quarter of 2022 of $33 million. In addition, a contract modification decreased the amount of revenue allocated to Rental income in Southern Appalachia beginning in the first quarter of 2023.
Product related revenue decreased $393 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices across all regions of $450 million, partially offset by higher volumes in the Southwest of $49 million.
Income from equity method investments increased $11 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our joint ventures in the Marcellus and Utica. Additionally, our joint venture in the Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.
34
Other income increased $20 million in the second quarter of 2023 compared to the same period of 2022 due primarily to a gain on disposal of assets recognized in the second quarter of 2023 of $13 million in addition to a loss on disposal of assets of $4 million recognized in the second quarter of 2022.
Cost of revenues decreased $6 million in the second quarter of 2023 compared to the same period of 2022. This decrease is attributable to lower operating costs and repairs and maintenance costs in the Rockies of $14 million, partially offset by higher operating costs in the Southwest of $8 million.
Purchased product costs decreased $309 million in the second quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $393 million in the Southwest and Southern Appalachia, partially offset by higher volumes in the Southwest of $90 million.
Six months ended June 30, 2023 compared to six months ended June 30, 2022
Service revenue increased $80 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to higher volumes, higher throughput fee rates and higher minimum volume commitments in the Marcellus and Rockies.
Rental income decreased $70 million and sales-type lease revenue increased $67 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to changes in the presentation of revenue between rental income and sales-type lease revenue as a result of the Third-Party Lease Modification in the third quarter of 2022.
Product related revenue decreased $490 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to lower prices across all regions of $648 million, partially offset by higher volumes in the Southwest of $147 million and changes in the fair value of our propane contracts of $10 million.
Income from equity method investments increased $27 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our joint ventures in the Marcellus and Utica. Additionally, our joint venture in the Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.
Other income increased $38 million in the first six months of 2023 compared to the same period of 2022 due primarily to a gain on disposal of assets recognized in the second quarter of 2023 of $13 million in addition to a loss on disposal of assets of $22 million recognized in the first half of 2022.
Purchased product costs decreased $370 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $550 million in the Southwest and Southern Appalachia, partially offset by higher volumes in the Southwest of $172 million.
Purchases - related parties increased $38 million in the first six months of 2023 compared to the same period of 2022. The increase is attributable to higher volumes and pricing on associated related-party purchased product costs in the Rockies and higher transportation costs from increased throughput in the Southwest.
Depreciation and amortization decreased $27 million in the first six months of 2023 compared to the same period of 2022. This was primarily due to lower depreciation as a result of the derecognition of fixed assets in connection with the Third-Party Lease Modification in the third quarter of 2022. This decrease was partially offset by depreciation on new assets placed in service after the second quarter of 2022.
35
G&P Operating Data
(1) Other includes Southern Appalachia, Bakken and Rockies Operations.
MPLX LP(1) | MPLX LP Operated(2) | ||||||||||||||||||||||
| Three Months Ended June 30, | Three Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| G&P | |||||||||||||||||||||||
| Gathering Throughput (MMcf/d) | |||||||||||||||||||||||
| Marcellus Operations | 1,321 | 1,287 | 1,321 | 1,287 | |||||||||||||||||||
| Utica Operations | — | — | 2,326 | 1,943 | |||||||||||||||||||
| Southwest Operations | 1,354 | 1,429 | 1,768 | 1,694 | |||||||||||||||||||
| Bakken Operations | 160 | 148 | 160 | 148 | |||||||||||||||||||
| Rockies Operations | 457 | 425 | 584 | 554 | |||||||||||||||||||
| Total gathering throughput | 3,292 | 3,289 | 6,159 | 5,626 | |||||||||||||||||||
| Natural Gas Processed (MMcf/d) | |||||||||||||||||||||||
| Marcellus Operations | 4,091 | 3,987 | 5,691 | 5,445 | |||||||||||||||||||
| Utica Operations | — | — | 547 | 522 | |||||||||||||||||||
| Southwest Operations | 1,517 | 1,449 | 1,848 | 1,638 | |||||||||||||||||||
| Southern Appalachian Operations | 219 | 231 | 219 | 231 | |||||||||||||||||||
| Bakken Operations | 159 | 142 | 159 | 142 | |||||||||||||||||||
| Rockies Operations | 470 | 440 | 470 | 440 | |||||||||||||||||||
| Total natural gas processed | 6,456 | 6,249 | 8,934 | 8,418 | |||||||||||||||||||
| C2 + NGLs Fractionated (mbpd) | |||||||||||||||||||||||
Marcellus Operations(3) | 520 | 471 | 520 | 471 | |||||||||||||||||||
Utica Operations(3) | — | — | 30 | 30 | |||||||||||||||||||
| Southern Appalachian Operations | 11 | 12 | 11 | 12 | |||||||||||||||||||
| Bakken Operations | 18 | 20 | 18 | 20 | |||||||||||||||||||
| Rockies Operations | 4 | 3 | 4 | 3 | |||||||||||||||||||
Total C2 + NGLs fractionated(4) | 553 | 506 | 583 | 536 | |||||||||||||||||||
36
MPLX LP(1) | MPLX LP Operated(2) | ||||||||||||||||||||||
| Six Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| G&P | |||||||||||||||||||||||
| Gathering Throughput (MMcf/d) | |||||||||||||||||||||||
| Marcellus Operations | 1,342 | 1,300 | 1,342 | 1,300 | |||||||||||||||||||
| Utica Operations | — | — | 2,393 | 1,879 | |||||||||||||||||||
| Southwest Operations | 1,367 | 1,369 | 1,792 | 1,586 | |||||||||||||||||||
| Bakken Operations | 158 | 147 | 158 | 147 | |||||||||||||||||||
| Rockies Operations | 450 | 410 | 574 | 540 | |||||||||||||||||||
| Total gathering throughput | 3,317 | 3,226 | 6,259 | 5,452 | |||||||||||||||||||
| Natural Gas Processed (MMcf/d) | |||||||||||||||||||||||
| Marcellus Operations | 4,068 | 4,001 | 5,623 | 5,487 | |||||||||||||||||||
| Utica Operations | — | — | 521 | 473 | |||||||||||||||||||
| Southwest Operations | 1,460 | 1,416 | 1,784 | 1,589 | |||||||||||||||||||
| Southern Appalachian Operations | 225 | 228 | 225 | 228 | |||||||||||||||||||
| Bakken Operations | 156 | 143 | 156 | 143 | |||||||||||||||||||
| Rockies Operations | 462 | 423 | 462 | 423 | |||||||||||||||||||
| Total natural gas processed | 6,371 | 6,211 | 8,771 | 8,343 | |||||||||||||||||||
| C2 + NGLs Fractionated (mbpd) | |||||||||||||||||||||||
Marcellus Operations(3) | 526 | 469 | 526 | 469 | |||||||||||||||||||
Utica Operations(3) | — | — | 30 | 27 | |||||||||||||||||||
| Southern Appalachian Operations | 11 | 11 | 11 | 11 | |||||||||||||||||||
| Bakken Operations | 18 | 20 | 18 | 20 | |||||||||||||||||||
| Rockies Operations | 3 | 4 | 3 | 4 | |||||||||||||||||||
Total C2 + NGLs fractionated(4) | 558 | 504 | 588 | 531 | |||||||||||||||||||
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Pricing Information | |||||||||||||||||||||||
| Natural Gas NYMEX HH ($ per MMBtu) | $ | 2.32 | $ | 7.50 | $ | 2.54 | $ | 6.04 | |||||||||||||||
C2 + NGL Pricing ($ per gallon)(5) | $ | 0.63 | $ | 1.18 | $ | 0.70 | $ | 1.16 | |||||||||||||||
(1) This column represents operating data for entities that have been consolidated into the MPLX financial statements.
(2) This column represents operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for MPLX-operated equity method investments.
(3) Entities within the Marcellus and Utica Operations jointly own the Hopedale fractionation complex. Hopedale throughput is included in the Marcellus and Utica Operations and represent each region’s utilization of the complex.
(4) Purity ethane makes up approximately 226 mbpd and 189 mbpd of MPLX LP consolidated total fractionated products for the three months ended June 30, 2023 and June 30, 2022, respectively, and approximately 236 mbpd and 187 mbpd of total fractionated products for the six months ended June 30, 2023 and June 30, 2022, respectively. Purity ethane makes up approximately 232 mbpd and 194 mbpd of MPLX LP Operated total fractionated products for the three months ended June 30, 2023 and June 30, 2022, respectively, and approximately 242 mbpd and 191 mbpd of total fractionated products for the six months ended June 30, 2023 and June 30, 2022, respectively.
(5) C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
Seasonality
The volume of crude oil and refined products transported and stored utilizing our assets is affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. The majority of effects of seasonality on the L&S segment’s revenues are mitigated through the use of fee-based transportation and storage services agreements with MPC that include minimum volume commitments.
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In our G&P segment, we experience minimal impacts from seasonal fluctuations which impact the demand for natural gas and NGLs and the related commodity prices caused by various factors including variations in weather patterns from year to year. We are able to manage the seasonality impacts through the execution of our marketing strategy. Overall, our exposure to the seasonality fluctuations is limited due to the nature of our fee-based business.
Liquidity and Capital Resources
Cash Flows
Our cash and cash equivalents were $755 million at June 30, 2023 and $238 million at December 31, 2022. 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 were as follows:
| Six Months Ended June 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Net cash provided by (used in): | |||||||||||
| Operating activities | $ | 2,664 | $ | 2,612 | |||||||
| Investing activities | (491) | (411) | |||||||||
| Financing activities | (1,656) | (1,916) | |||||||||
| Total | $ | 517 | $ | 285 | |||||||
Net cash provided by operating activities increased $52 million in the first six months of 2023 compared to the same period of 2022, primarily due to improved results from operations partially offset by higher favorable working capital changes during the first six months of 2022 compared to the same period of 2023.
Net cash used in investing activities increased $80 million in the first six months of 2023 compared to the same period of 2022, due to higher capital spending. The increase in the first six months of 2023 was partially offset by higher contributions to equity method investments for the first half of 2022, which included a $60 million contribution to our Bakken Pipeline joint venture to fund our share of a scheduled debt repayment by the joint venture.
Net cash used in financing activities decreased $260 million in the first six months of 2023 compared to the same period of 2022. The decrease was driven by net borrowings in the first half of 2023 as compared to net repayments in the first half of 2022, resulting in a decreased use of cash of $854 million. There was also lower spending on the unit repurchase program of $135 million in the first half of 2023 compared to the same period of 2022. The decrease in the use of cash was partially offset by the use of $600 million to redeem the Series B units and by $127 million of higher distributions paid to unitholders during the first six months of 2023 compared to the same period of 2022, as a result of the 10 percent increase in our base distribution effective for the third quarter of 2022.
Adjusted Free Cash Flow
The following table provides a reconciliation of Adjusted FCF and Adjusted FCF after distributions from net cash provided by operating activities for the three and six months ended June 30, 2023 and June 30, 2022.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||||||||
| (In millions) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||||||||
Net cash provided by operating activities(1) | $ | 1,437 | $ | 1,487 | $ | 2,664 | $ | 2,612 | |||||||||||||||||||||
| Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow | |||||||||||||||||||||||||||||
| Net cash used in investing activities | (271) | (135) | (491) | (411) | |||||||||||||||||||||||||
| Contributions from MPC | 5 | 7 | 13 | 17 | |||||||||||||||||||||||||
| Distributions to noncontrolling interests | (9) | (10) | (19) | (19) | |||||||||||||||||||||||||
| Adjusted free cash flow | 1,162 | 1,349 | 2,167 | 2,199 | |||||||||||||||||||||||||
| Distributions paid to common and preferred unitholders | (799) | (735) | (1,620) | (1,493) | |||||||||||||||||||||||||
| Adjusted free cash flow after distributions | $ | 363 | $ | 614 | $ | 547 | $ | 706 | |||||||||||||||||||||
(1) The three months ended June 30, 2023 and June 30, 2022 include working capital draws of $160 million and $266 million, respectively. The six months ended June 30, 2023 and June 30, 2022 include working capital draws of $112 million and $148 million, respectively.
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Debt and Liquidity Overview
On February 9, 2023, MPLX issued $1.6 billion aggregate principal amount of notes, consisting of $1.1 billion principal amount of 5.00 percent senior notes due 2033 (the “2033 Senior Notes”) and $500 million principal amount of 5.65 percent senior notes due 2053 (the “2053 Senior Notes”). The 2033 Senior Notes were offered at a price to the public of 99.170 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023. The 2053 Senior Notes were offered at a price to the public of 99.536 percent of par with interest payable semi-annually in arrears, commencing on September 1, 2023.
On February 15, 2023, MPLX used $600 million of the net proceeds from the offering of the 2033 Senior Notes and 2053 Senior Notes described above to redeem all of the outstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and cash on hand, to redeem all of MPLX’s and MarkWest’s $1.0 billion aggregate principal amount of 4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest.
Our intention is to maintain an investment-grade credit profile. As of June 30, 2023, the credit ratings on our senior unsecured debt were as follows:
| Rating Agency | Rating | |||||||
| Moody’s | Baa2 (stable outlook) | |||||||
| Standard & Poor’s | BBB (stable outlook) | |||||||
| Fitch | BBB (stable outlook) | |||||||
The ratings reflect the respective views of the rating agencies and should not be interpreted as a recommendation to buy, sell or hold our securities. 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. A rating from one rating agency should be evaluated independently of ratings from other rating agencies.
The agreements governing our debt obligations do not contain credit rating triggers that would result in the acceleration of interest, principal or other payments solely in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings to below investment grade ratings could, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement and may limit our ability to obtain future financing, including refinancing existing indebtedness.
Our liquidity totaled $4.3 billion at June 30, 2023 consisting of:
| June 30, 2023 | |||||||||||||||||
| (In millions) | Total Capacity | Outstanding Borrowings | Available Capacity | ||||||||||||||
MPLX Credit Agreement(1) | $ | 2,000 | $ | — | $ | 2,000 | |||||||||||
| MPC Loan Agreement | 1,500 | — | 1,500 | ||||||||||||||
| Total | $ | 3,500 | $ | — | 3,500 | ||||||||||||
| Cash and cash equivalents | 755 | ||||||||||||||||
| Total liquidity | $ | 4,255 | |||||||||||||||
(1) Outstanding borrowings include less than $1 million in letters of credit outstanding under this facility.
We expect our ongoing sources of liquidity to include cash generated from operations and borrowings under our revolving credit facilities and access to capital markets. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations, and quarterly cash distributions. Our material future obligations include interest on debt, payments of debt principal, purchase obligations including contracts to acquire plant, property and equipment, and our operating leases and service agreements. We may also, from time to time, repurchase our senior notes or preferred units in the open market, in tender offers, in privately negotiated transactions or otherwise in such volumes, at market prices and upon such other terms as we deem appropriate and execute unit repurchases under our unit repurchase program. 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 under our omnibus agreement. 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.
The MPLX Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type. The financial covenant 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 during the six-month period 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,
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creating liens on assets and entering into transactions with affiliates. As of June 30, 2023, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.5 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.
Equity and Preferred Units Overview
Unit Repurchase Program
On August 2, 2022 we announced the board authorization for the repurchase of up to an additional $1.0 billion of MPLX common units held by the public. The authorization has no expiration date. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated unit repurchases, tender offers or open market solicitations for units, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
No units were repurchased during the six months ended June 30, 2023. As of June 30, 2023, we had $846 million remaining under the repurchase authorization.
Redemption of the Series B Preferred Units
On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding units of 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”). MPLX paid unitholders the Series B preferred unit redemption price of $1,000 per unit. See Note 5 to the unaudited consolidated financial statements for more information.
Distributions on the Series B preferred units were 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. In accordance with these terms, MPLX made a final cash distribution of $21 million to Series B preferred unitholders on February 15, 2023, in conjunction with the redemption.
Distributions
We intend to pay 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. The amount of distributions paid under our policy and the decision to make any distributions is determined by our general partner, taking into consideration the terms of our partnership agreement. Such minimum distribution would equate to $263 million per quarter, or $1,051 million per year, based on the number of common units outstanding at June 30, 2023.
On July 25, 2023, MPLX declared a cash distribution for the second quarter of 2023, totaling $776 million, or $0.775 per common unit. This distribution will be paid on August 14, 2023 to common unitholders of record on August 4, 2023. 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. This rate will also be received by Series A preferred unitholders.
The allocation of total cash distributions is as follows for the three and six months ended June 30, 2023 and June 30, 2022. 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.
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| (In millions, except per unit data) | 2023 | 2022 | 2023 | 2022 | |||||||||||||||||||
| Distribution declared: | |||||||||||||||||||||||
| Limited partner units - public | $ | 274 | $ | 257 | $ | 548 | $ | 514 | |||||||||||||||
| Limited partner units - MPC | 502 | 457 | 1,004 | 913 | |||||||||||||||||||
| Total LP distribution declared | 776 | 714 | 1,552 | 1,427 | |||||||||||||||||||
| Series A preferred units | 23 | 21 | 46 | 42 | |||||||||||||||||||
Series B preferred units(1) | — | 10 | 5 | 21 | |||||||||||||||||||
| Total distribution declared | $ | 799 | $ | 745 | 1,603 | 1,490 | |||||||||||||||||
| Quarterly cash distributions declared per limited partner common unit | $ | 0.775 | $ | 0.705 | $ | 1.5500 | $ | 1.4100 | |||||||||||||||
(1) The six months ended June 30, 2023, includes the portion of the $21 million distribution paid to the Series B preferred unitholders on February 15, 2023 that was earned during the period prior to redemption.
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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 growth capital expenditures and maintenance capital expenditures. Growth capital expenditures are those incurred for acquisitions or capital improvements that we expect will increase our operating capacity for volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of growth capital expenditures include costs to develop or acquire additional pipeline, terminal, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for MPLX. In contrast, 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.
MPLX’s initial capital investment plan for 2023 totals $950 million, net of reimbursements, which includes growth capital of $800 million and maintenance capital of $150 million. Growth capital expenditures and investments in affiliates during the six months ended June 30, 2023 were primarily for gas processing plants and gathering projects in the Marcellus and Permian basins, as well as additions to our brown water marine fleet. We continuously evaluate our capital plan and make changes as conditions warrant.
Our capital expenditures are shown in the table below:
| Six Months Ended June 30, | |||||||||||
| (In millions) | 2023 | 2022 | |||||||||
| Capital expenditures: | |||||||||||
| Growth capital expenditures | $ | 366 | $ | 278 | |||||||
Growth capital reimbursements(1) | (80) | (32) | |||||||||
| Investments in unconsolidated affiliates | 77 | 156 | |||||||||
| Capitalized interest | (6) | (5) | |||||||||
Total growth capital expenditures(2) | 357 | 397 | |||||||||
| Maintenance capital expenditures | 78 | 70 | |||||||||
| Maintenance capital reimbursements | (13) | (17) | |||||||||
| Capitalized interest | (1) | — | |||||||||
| Total maintenance capital expenditures | 64 | 53 | |||||||||
| Total growth and maintenance capital expenditures | 421 | 450 | |||||||||
Investments in unconsolidated affiliates(3) | (77) | (156) | |||||||||
Growth and maintenance capital reimbursements(4) | 93 | 49 | |||||||||
| Increase in capital accruals | (12) | (54) | |||||||||
| Capitalized interest | 7 | 5 | |||||||||
Additions to property, plant and equipment(3) | $ | 432 | $ | 294 | |||||||
(1) Growth capital reimbursements include reimbursements from customers and our Sponsor. Prior periods have been updated to reflect these reimbursements to conform to the current period presentation.
(2) Total growth capital expenditures exclude $28 million of acquisitions for the six months ended June 30, 2022.
(3) Investments in unconsolidated affiliates and additions to property, plant and equipment are shown as separate lines within investing activities in the Consolidated Statements of Cash Flows.
(4) Growth capital reimbursements are included in changes in deferred revenue within operating activities in the Consolidated Statements of Cash Flows. Maintenance capital reimbursements are included in the Contributions from MPC line within financing activities in the Consolidated Statements of Cash Flows.
Contractual Cash Obligations
As of June 30, 2023, our contractual cash obligations included debt, finance and operating lease obligations, purchase obligations for services and to acquire property, plant and equipment, and other liabilities. During the six months ended June 30, 2023, our debt obligations increased by $600 million due to the issuance of Senior Notes and use of proceeds described above in Liquidity and Capital Resources-Debt and Liquidity Overview. There were no other material changes to our contractual obligations outside the ordinary course of business since December 31, 2022.
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Off-Balance Sheet Arrangements
Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to guarantees that are described in Note 14 of the unaudited consolidated financial statements and indemnities as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022.
Although these arrangements serve a variety of our business purposes, we are not dependent on them to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on our liquidity and capital resources.
Transactions with Related Parties
At June 30, 2023, MPC owned our non-economic general partnership interest and held approximately 65 percent of our outstanding common units.
We provide MPC with crude oil, product pipeline, and trucking transportation services based on regulated tariff/contracted rates, as well as storage, terminal, fuels distribution, and inland marine transportation services based on contracted rates. We also have agreements with MPC under which we receive fees for operating MPC’s retained pipeline assets, providing management services for the marine business, and operating certain of MPC’s equity method investments. MPC provides us with certain services related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services under employee services and omnibus services agreements.
The below table shows the percentage of Total revenues and other income as well as Total costs and expenses with MPC:
| Three Months Ended June 30, | Six Months Ended June 30, | ||||||||||||||||||||||
| 2023 | 2022 | 2023 | 2022 | ||||||||||||||||||||
| Total revenues and other income | 50 | % | 45 | % | 50 | % | 46 | % | |||||||||||||||
| Total costs and expenses | 27 | % | 23 | % | 27 | % | 24 | % | |||||||||||||||
For further discussion of agreements and activity with MPC and related parties see Item 1. Business in our Annual Report on Form 10-K for the year ended December 31, 2022 and Note 4 to the unaudited consolidated financial statements in this report.
Environmental Matters and Compliance Costs
We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and 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.
As previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements. There have been no significant changes to our environmental matters and compliance costs during the six months ended June 30, 2023.
Critical Accounting Estimates
As of June 30, 2023, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, 2022.
Accounting Standards Not Yet Adopted
We have not identified any recent accounting pronouncements that are expected to have a material impact on our financial condition, results of operations or cash flows upon adoption. Accounting standards are discussed in Note 2 of the unaudited consolidated financial statements.
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Item 3. 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 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 June 30, 2023, we did not have any open financial derivative instruments to hedge the economic risks related to interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these arrangements in the future.
Commodity Price Risk
The information about commodity price risk for the three and six months ended June 30, 2023 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2022.
Outstanding Derivative Contracts and Sensitivity Analysis
See Notes 9 and 10 to the unaudited consolidated financial statements for more information about the fair value measurement of our derivative instruments, including the natural gas embedded derivative, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.
Our open derivative positions at June 30, 2023 will expire at various times through 2023. We prepared a sensitivity analysis to estimate our exposure to market risk associated with our derivative instruments. Based on our open net positions at June 30, 2023, a 10 percent change in quoted market prices of our derivative instruments, assuming all other factors remain constant, could change the fair value of our derivative instruments and Income before income taxes by $2.0 million. This analysis may differ from actual results.
Interest Rate Risk and Sensitivity Analysis
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on outstanding third-party debt, excluding finance leases, is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
| (In millions) | Fair Value as of June 30, 2023(1) | Change in Fair Value(2) | Change in Income Before Income Taxes for the Three Months Ended June 30, 2023(3) | ||||||||||||||
| Outstanding debt | |||||||||||||||||
| Fixed-rate | $ | 18,671 | $ | 1,523 | N/A | ||||||||||||
Variable-rate(4) | $ | — | $ | — | $ | — | |||||||||||
(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 June 30, 2023.
(3) Assumes a 100-basis-point change in interest rates. The change to income before income taxes was based on the weighted average balance of all outstanding variable-rate debt for the six months ended June 30, 2023.
(4) MPLX had no outstanding borrowings on the MPLX Credit Agreement as of June 30, 2023.
At June 30, 2023, our portfolio of third‑party debt consisted of fixed-rate instruments and outstanding borrowings, if any, under the MPLX Credit Agreement. 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 MPLX Credit Agreement, but may affect our results of operations and cash flows.
See Note 9 in the unaudited consolidated financial statements for additional information on the fair value of our debt.
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Item 4. Controls and Procedures
Disclosure Controls and Procedures
An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the chief executive officer and chief financial officer of our general partner. Based upon that evaluation, the chief executive officer and chief financial officer of our general partner concluded that the design and operation of these disclosure controls and procedures were effective as of June 30, 2023, the end of the period covered by this report.
Changes in Internal Control Over Financial Reporting
During the quarter ended June 30, 2023, 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.
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Part II – Other Information
Item 1. 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.
Item 103 of Regulation S-K promulgated by the SEC requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions, unless we reasonably believe that the matter will result in no monetary sanctions, or in monetary sanctions, exclusive of interest and costs, of less than a specified threshold. We use a threshold of $1 million for this purpose.
There have been no material changes to the legal matters previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022, or in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2023.
Item 1A. Risk Factors
There have been no material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022.
Item 5. Other Information
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Item 6. Exhibits
| Incorporated by Reference From | ||||||||||||||||||||||||||||||||||||||||||||
| Exhibit Number | Exhibit Description | Form | Exhibit | Filing Date | SEC File No. | Filed Herewith | Furnished Herewith | |||||||||||||||||||||||||||||||||||||
| 3.1 | S-1 | 3.1 | 7/2/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 3.2 | S-1/A | 3.2 | 10/9/2012 | 333-182500 | ||||||||||||||||||||||||||||||||||||||||
| 3.3 | 8-K | 3.1 | 2/3/2021 | 001-35714 | ||||||||||||||||||||||||||||||||||||||||
| 10.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.3 | X | |||||||||||||||||||||||||||||||||||||||||||
| 10.4 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 31.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.1 | X | |||||||||||||||||||||||||||||||||||||||||||
| 32.2 | X | |||||||||||||||||||||||||||||||||||||||||||
| 101.INS | XBRL Instance Document: The instance document does not appear in the interactive data file because its XBRL tags are embedded within the Inline XBRL document. | |||||||||||||||||||||||||||||||||||||||||||
| 101.SCH | Inline XBRL Taxonomy Extension Schema Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.CAL | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.DEF | Inline XBRL Taxonomy Extension Definition Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.LAB | Inline XBRL Taxonomy Extension Label Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 101.PRE | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | X | ||||||||||||||||||||||||||||||||||||||||||
| 104 | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||||||||||||||||||||||||||||||||||||||||||
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SIGNATURES
Pursuant to the requirements 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.
| MPLX LP | |||||||||||
| By: | MPLX GP LLC | ||||||||||
| Its general partner | |||||||||||
| Date: August 1, 2023 | By: | /s/ Kelly D. Wright | |||||||||
| Kelly D. Wright | |||||||||||
| Vice President and Controller of MPLX GP LLC (the general partner of MPLX LP) | |||||||||||
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Exhibit 10.1
FIFTH AMENDMENT TO
TERMINAL SERVICES AGREEMENT
This Fifth Amendment to Terminal Services Agreement (“Amendment”) is made and entered into as of June 1, 2023 (“Amendment Date”) with respect to each respective Terminal set forth on Schedule I, unless otherwise indicated, the party identified as “Customer” with respect to such respective Terminal as set forth on Schedule I (such party, as applicable to the respective Terminal, a “Customer”), and the party identified as “Terminal Owner” with respect to such respective Terminal as set forth on Schedule I (such party, as applicable to the respective Terminal, a “Terminal Owner”) each referred to in this Amendment as a “Party” and collectively as “Parties”.
WHEREAS, on November 1, 2020, the Parties entered into that certain Terminal Services Agreement, subsequently amended on April 30, 2021, May 30, 2021, June 30, 2021, and July 31, 2021, (collectively, the “Agreement”), pursuant to which the Parties agreed that Terminal Owner would operate the Terminal or otherwise provide certain terminal services to the Customer at the respective Terminal;
WHEREAS, Tesoro Refining & Marketing Company LLC (“TRMC”) assigned and Marathon Petroleum Supply and Trading LLC assumed all of TRMC’s right, title and interest under the Agreement pertaining to crude petroleum;
WHEREAS, TRMC, Western Refining Company LLC (formerly known as Western Refining Company L.P., “WNR”), St. Paul Park Refining Co. LLC (“SPPR”), and Tesoro Alaska Company LLC (“TAC”) assigned and Marathon Petroleum Company LP assumed all of their rights, titles, and interests under the Agreement pertaining to all commodities other than crude petroleum; and
WHEREAS, the Parties desire to amend the Agreement to update the Initial Term, Base Throughput Fee, Minimum Terminal Volume Commitment, and make other conforming changes to the Agreement with respect to certain Terminals;
NOW, THEREFORE, in consideration of the promises and covenants in the Agreement and this Amendment and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties hereby agree as follows:
1.Schedule 1.1(A), Schedule I, Schedule 5.1, Schedule 5.1(c), and Schedule 14.1 are deleted in their entirety and replaced with Schedule 1.1(A), Schedule I, Schedule 5.1, Schedule 5.1 (c), and Schedule 14.1, respectively, attached hereto.
2.Schedule 5.1(d) is hereby added to the Agreement and incorporated herein.
3.In all other respects, except as herein modified, the terms and provisions of the Agreement shall remain in full force and effect.
4.In the event of any conflict between the terms and provisions of this Amendment and terms and provisions of the Agreement, the terms and provisions of this Amendment shall prevail.
5.The Parties acknowledge that this Amendment may be executed utilizing an electronic signature process. By signing electronically, the Parties further acknowledge that they each have read, understand, and are bound to the terms and conditions hereof in the same manner as if the Parties had signed this Amendment with handwritten original signatures.
[Signature Page Follows]
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Anacortes
Boise
Burley
Carson
Colton
Hynes
Mandan
Pasco
Pocatello
Salt Lake City
San Diego
Stockton
Vancouver
Vinvale
Wilmington
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Marathon Petroleum Supply and Trading LLC | ||||||||||||||
| By: | /s/ Rick D. Hessling | |||||||||||||
| Name: | Rick D. Hessling | |||||||||||||
| Title: | President | |||||||||||||
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Anchorage Ocean Dock
Anchorage T2
Fairbanks
Nikiski
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Tesoro Alaska Terminals LLC | ||||||||||||||
| By: | /s/ Shawn Lyon | |||||||||||||
| Name: | Shawn Lyon | |||||||||||||
| Title: | President | |||||||||||||
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Albuquerque
Bloomfield
El Paso
St. Paul Park
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Western Refining Terminals LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Schedule 1.1 (A) – Products
Bio-Diesel
Bio-Blended Diesel
Crude (Hynes Terminal Only)
Denatured Ethanol
Diesel
Ethanol
Gasoline
Jet
Kerosene
Propane
Renewable Diesel
Schedule I
Parties to Agreement per respective Terminal
| Terminal | Customer | Terminal Owner | Initial Term | Extension Period | ||||||||||
| Albuquerque | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Anacortes | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 1, 2024 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Anchorage Ocean Dock | Marathon Petroleum Company LP | Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an Extension Period by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Anchorage T2 | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC/Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Renewal Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Bloomfield | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Boise | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date – July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Burley | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Carson | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Colton | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| El Paso | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Fairbanks | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC/Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Hynes | Marathon Petroleum Company LP Marathon Petroleum Supply and Trading LLC (for crude only) | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Mandan | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Nikiski | Marathon Petroleum Company LP | Tesoro Alaska Terminals LLC | Effective Date September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Pasco | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date – July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Pocatello | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Salt Lake City | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| San Diego | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| St Paul Park | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - September 15, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 90 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Stockton | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Vancouver | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Vinvale | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Wilmington | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
Schedule 5.1 - Minimum Terminal Volume Commitment, Base Throughput Fee
| Terminal | State | Region | Minimum Terminal Volume Commitment (bpd) | Base Throughput Fee per Barrel | Shortfall Credit Carry-Forward Period | ||||||||||||
| Albuquerque^ | NM | LA | 7,500 | 0.63 | 12 months | ||||||||||||
| Anacortes | WA | PNW | 12,000 | 1.248927 | 3 months | ||||||||||||
| Anchorage Ocean Dock | AK | PNW | 17,000 | 4.728224 | 3 months | ||||||||||||
| Anchorage T2 | AK | PNW | 6,790 | 3.736476 | 3 months | ||||||||||||
| Bloomfield^ | NM | LA | 5,000 | 0.63 | 12 months | ||||||||||||
| Boise* | ID | PNW | 7,200 | 0.813503 | 3 months | ||||||||||||
| Burley* | ID | PNW | 2,300 | 0.756338 | 3 months | ||||||||||||
| Carson+ | CA | LA | 6,000 | 1.0500 | 3 months | ||||||||||||
| Colton+ | CA | LA | 30,500 | 0.7560 | 3 months | ||||||||||||
| El Paso^ | TX | LA | 26,000 | 0.63 | 12 months | ||||||||||||
| Fairbanks | AK | PNW | 595 | 1.1142421 | 3 months | ||||||||||||
| Hynes+ | CA | LA | 23,000 | 1.0500 | 3 months | ||||||||||||
| Mandan* | ND | CHI | 12,400 | 0.685981 | 3 months | ||||||||||||
| Nikiski | AK | PNW | 3,000 | 3.984154 | 3 months | ||||||||||||
| Pasco* | WA | PNW | 3,500 | 0.786000 | N/A | ||||||||||||
| Pocatello* | ID | PNW | 1,500 | 0.786000 | N/A | ||||||||||||
| Salt Lake City* | UT | PNW | 27,300 | 0.642008 | 3 months | ||||||||||||
| San Diego+ | CA | LA | 17,000 | 0.7560 | 3 months | ||||||||||||
| St Paul Park | MN | CHI | 35,561 | 0.591214 | 12 months | ||||||||||||
| Stockton* | CA | SF | 7,000 | 0.923436 | 3 months | ||||||||||||
| Vancouver* | WA | PNW | 6,400 | 0.927834 | 3 months | ||||||||||||
| Vinvale+ | CA | LA | 67,500 | 1.0500 | 3 months | ||||||||||||
| Wilmington* | CA | LA | 33,300 | 1.152097 | 3 months | ||||||||||||
*The Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be effective through July 31, 2024, and will be subject to negotiation by the Parties thereafter; provided, however, in no event will the new Minimum Terminal Volume Commitment be less than 75% of the current cumulative Minimum Terminal Volume Commitment for these Terminals. If the Parties are unable to complete negotiations by August 1, 2024, the existing Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will remain in effect until such negotiations are final. Once finalized, the new Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be applied retroactively effective as of August 1, 2024.
^ The Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be effective through October 16, 2026, and will be subject to negotiation by the Parties thereafter; provided, however, in no event will the new Minimum Terminal Volume Commitment be less than 75% of the current cumulative Minimum Terminal Volume Commitment for these Terminals. If the Parties are unable to complete negotiations by December 31, 2026, the existing Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will remain in effect until such negotiations are final. Once finalized, the new Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be applied retroactively effective as of January 1, 2027.
+ The Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be effective through May 31, 2026, and will be subject to negotiation by the Parties thereafter; provided,
however, in no event will the new Minimum Terminal Volume Commitment be less than 75% of the current cumulative Minimum Terminal Volume Commitment for these Terminals. If the Parties are unable to complete negotiations by August 31, 2026, the existing Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will remain in effect until such negotiations are final. Once finalized, the new Minimum Terminal Volume Commitment and Base Throughput Fee for these Terminals will be applied retroactively effective as of September 1, 2026.
Light Product Terminal Complexes:
1.Albuquerque, Bloomfield, and El Paso
2.Carson, Colton, Hynes, San Diego and Vinvale
3.Boise, Burley, Mandan, Pocatello, Pasco, Salt Lake City, Stockton, Vancouver, and Wilmington.
4.Anchorage T2 and Anchorage Ocean Dock
Butane Blending
A) Facilities with Third Party Licensed Blending Technology
At facilities at which third-party license blending technology to Customer, Terminal Owner's fee for performing the butane blending service shall be calculated as follows:
Ninety-five percent (95%) of the difference between the Daily Gasoline Value (defined below) and the Daily Butane Value (defined below). Expressed as a formula, the Butane Blending Service Fee is:
Butane Blending Service Fee = (DGV-DBV)* 95%
NOTE: Terminal Owner will reflect an Annual True-Up, as defined in Section 3 of this Schedule 5.1, as a separate line item on any monthly invoices submitted pursuant to this Agreement.
Definitions:
1. Daily Gasoline Value (“DGV”): Expressed as a formula:
DGV = (GB)*(GPV+TF).
GB: number of Gallons of butane blended on a given day at the terminal site.
GPV: daily gasoline posted value per Gallon.
TF: the transportation fee for moving spot purchased gasoline to the terminal for the gasoline grade in which the butane is blended.
GPV is calculated by location as follows:
GPV Calculation Table
Location | Market | GPV Price Calculation | ||||||
The Parties may update the GPV Calculation Table without formal amendment of the Agreement upon written approval by each Party. The latest agreed upon GPV Calculation Table shall be the effective GPV Calculation Table. Terminal Owner shall maintain the current and previous versions of the GPV Calculation Table.
TF is the avoided Customer cost of transporting one Gallon of gasoline (in the most cost effective method possible) to a terminal blending location, as verified and provided by Customer’s Global Clean Products Value Chain organization.
2. Daily Butane Value (“DBV”): the daily agreed upon butane purchase price (“BPP”) from ETP plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane gallons blended (“GB”). Expressed as a formula:
DBV = (GB)*(BPP+DRV)
DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually or the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, postings for prior years RINs will be used up to the maximum allowable percentage.
3. Annual True-Up: This cost or revenue is intended to cover changes in the estimated vs actual transportation costs, half of shared maintenance expenses, and estimated vs actual butane purchase costs. The cost or revenue is calculated by Energy Transfer Partners (“ETP”). Customer will pass ninety-five (95%) of this to Terminal Owner.
B) Facilities without Third Party Blending Technology
At facilities at which no third party licensed blending technology is utilized, Terminal Owner’s fee for performing the butane or pentane blending service shall be calculated as follows:
Ninety-five percent (95%) of the difference between the Tank Daily Gasoline Value (defined below) and the Tank Daily Butane Value (defined below). Expressed as a formula, the Tank Butane Blending Service Fee is:
Tank Butane Blending Service Fee = (TDGV-TDBV)* 95%
Definitions
1. Tank Daily Gasoline Value (“TDGV”): Expressed as a formula:
TDGV = (GB)*(GPV+TF)
GB: number of Gallons of butane blended on a given day at the terminal site.
GPV: daily gasoline spot price per gallon.
TF: the avoided transportation fee for moving spot purchased gasoline to the terminal for the gasoline grade in which the butane is blended.
GPV is calculated by Terminal, described in Schedule 5.1, as follows:
LA and SF regions: daily posted OPIS Mid 84 Sub-octane Regular or OPIS Mid 88.5 Sub-octane Premium spot price for the respective blend.
PNW region: daily posted OPIS Mid 84 Sub-octane Regular or OPIS Mid 90 Sub-octane Premium spot price for the respective blend.
CHI region: daily posted Argus Mid 85 CBOB or Argus Mid PREM spot price for the respective blend.
2. Tank Daily Butane Value (“TDBV”): the daily agreed upon tank butane purchase price (“TBPP”) from supplier, plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane Gallons blended (“GB”). Expressed as a formula:
TDBV = (GB)*(TBPP+DRV+TC)
TC is the trucking cost of transporting one Gallon of butane (in the most cost effective method possible) to a terminal blending location.
DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually to the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, posting for prior years RINs will be used up to the maximum allowable percentage.
In the event Customer requests a butane skid for temporary use at a Customer owned terminal(s), Customer shall pay a Terminal Owner Tank Butane Blending Equipment Service Fee equal to 5% of the blending value. Expressed as a formula:
Terminal Owner Tank Butane Blending Equipment Service Fee = (TDGV-TDBV)* 5%.
Annual Adjustment to Revenue: This cost or revenue is intended to cover changes in the estimated vs actual transportation costs. Annually during the month of April, Customer will issue an adjustment of revenue to Terminal Owner. This adjustment will be the result in changes of actual vs previously estimated trucking costs associated with delivery of butane to the terminals for the previous April – March.
Ethanol Excess Volume Value Capture
Customer will pay Terminal Owner fees as calculated herein for EV at Terminals where sales volume is made on a temperature corrected basis.
The value will be calculated via the following method: Multiply the volume by the price per the calculations described in the following two paragraphs.
The volume will be calculated via the following method: The American Petroleum Institute’s Manual of Petroleum Measurement Standards Chapter 11.3.4 “Miscellaneous Hydrocarbon Properties – Denatured Ethanol and Gasoline Blend Densities and Volume Correction Factors” (“Chapter 11.3.4”) provides data-based equations for Blends of Gasoline and Ethanol (“BGE”). Chapter 11.3.4 addresses excess volumes of gasohol (“EV”) created when gasoline and ethanol components are blended together. EV for truck rack throughput at Terminals equipped with Terminal Automation Software (TAS) will be calculated using the equation in Chapter 11.3.4 performed by TAS for any BGE. The TAS will be programmed to calculate EV by multiplying these BGE volumes by the correction factors as calculated using the equation from Chapter 11.3.4. This process of crediting Terminal Owner with the EV based on the technology Terminal Owner installed and maintains at its Terminals is known as “Ethanol Excess Volume Value Capture.”
The price will be calculated via the following method: each Terminal is assigned to a Region based on Schedule 5.1. EV credited to Terminal Owner will be valued using the non-weighted monthly average spot price for the Region each Terminal is assigned to in Schedule 5.1. Spot prices are as follows: for the LA, SF and PNW Regions use OPIS Mid 84 Sub-octane Regular; for the CHI Region use Argus Mid 85 CBOB (West Shore).
Schedule 5.1(c) – Storage Fees and Monthly Storage Commitment
| Terminal Name | State | Monthly Storage Commitment (Barrels) | Storage Services Fee (per Barrel) | ||||||||
Albuquerque1 | NM | 155,959 | 0.6000 | ||||||||
| Anchorage Ocean Dock | AK | 316,000 | 1.241742 | ||||||||
| Anchorage T2 | AK | 342,000 | 1.241742 | ||||||||
Bloomfield1 | NM | 142,017 | 0.6000 | ||||||||
| El Paso | TX | 74,898 | 0.6000 | ||||||||
Hynes – Refined products3 | CA | 967,662 | 1.2000 | ||||||||
Hynes – Crude/Dark Oil2,3 | CA | 676,910 | 1.0123 | ||||||||
| Pocatello | ID | 19,307 | 0.2800 | ||||||||
| St. Paul Park | MN | 11,808 | 0.594940 | ||||||||
Vinvale3 | CA | 528,573 | 1.2000 | ||||||||
1 Terminal Owner may, but shall have no obligation to, utilize any shell capacity not being used by Customer to provide storage to third parties; provided, however, that Terminal Owner shall be required, to the extent Customer desires to utilize any then-available storage capacity, to prioritize Customer’s utilization of such storage capacity over third-party customers.
2 The Crude/Dark Oil Monthly Storage Commitment and Storage Services Fee for this Terminal will be effective through May 31, 2026, and will be subject to negotiation by the Parties thereafter; provided, however, in no event will the new Crude/Dark Oil Monthly Storage Commitment be less than 272,662 barrels per month or the Storage Services Fee be less than 75% of the current Storage Services Fee for this Terminal. If the Parties are unable to mutually agree on an adjusted Monthly Storage Commitment and Storage Services Fee by August 31, 2026, the existing Monthly Storage Commitment and Storage Services Fee for this Terminal will remain in effect through the remaining Term of this Agreement.
3 Shell Capacity per dedicated tank with the included tank number, shell capacity, and Product is included in Schedule 5.1 (d) of this Agreement.
Schedule 5.1 (d) - Tanks, Product, and Shell Capacity
Hynes TSA - Storage - Shell Capacity Dedicated Tanks
| Terminal | Tank | Product | Shell Capacity (in Barrels) | ||||||||
| East Hynes | 714 | Refined Product/Component | 136,331 | ||||||||
| East Hynes | 716 | Refined Product/Component | 136,331 | ||||||||
| East Hynes | 731 | Refined Product/Component | 132,508 | ||||||||
| East Hynes | 732 | Refined Product/Component | 132,508 | ||||||||
| East Hynes | 733 | Refined Product/Component | 133,431 | ||||||||
| East Hynes | 734 | Crude/Dark Oil | 132,508 | ||||||||
| East Hynes | 735 | Crude/Dark Oil | 132,508 | ||||||||
| East Hynes | 736 | Crude/Dark Oil | 139,232 | ||||||||
| East Hynes | 765 | Refined Product/Component | 19,192 | ||||||||
| East Hynes | 792 | Refined Product/Component | 76,596 | ||||||||
| East Hynes | 794 | Refined Product/Component | 122,254 | ||||||||
| East Hynes | 796 | Refined Product/Component | 78,511 | ||||||||
| East Hynes | 605 | Crude/Dark Oil | 136,331 | ||||||||
| East Hynes | 606 | Crude/Dark Oil | 136,331 | ||||||||
| Total Shell Capacity | 1,644,572 | ||||||||||
| Total Dedicated Crude/Dark Oil Shell Capacity | 676,910 | ||||||||||
| Total Dedicated Refined Product/Component Shell Capacity | 967,662 | ||||||||||
Vinvale TSA - Storage - Shell Capacity Dedicated Tanks
| Terminal | Tank | Product | Shell Capacity (in Barrels) | ||||||||
| Vinvale | 933 | Gasoline | 129,667 | ||||||||
| Vinvale | 934 | Gasoline | 133,045 | ||||||||
| Vinvale | 941 | Ethanol | 134,266 | ||||||||
| Vinvale | 943 | Gasoline | 131,595 | ||||||||
| Total Dedicated Shell Capacity | 528,573 | ||||||||||
Albuquerque TSA – Storage – Shell Capacity Dedicated Tanks
| Terminal | Tank | Product | Shell Capacity (in Barrels) | ||||||||
| Albuquerque | 25 | Gasoline | 25,181 | ||||||||
| Albuquerque | 26 | Ethanol | 16,787 | ||||||||
| Albuquerque | 27 | Ethanol | 16,787 | ||||||||
| Albuquerque | 30 | Gasoline | 16,787 | ||||||||
| Albuquerque | 31 | Gasoline | 42,976 | ||||||||
| Albuquerque | 32 | Gasoline | 16,787 | ||||||||
| Albuquerque | 33 | Gasoline | 16,787 | ||||||||
| Albuquerque | 53 | ULSD | 16,787 | ||||||||
| Albuquerque | 96 | ULSD | 16,787 | ||||||||
| Total Shell Capacity | 185,666 | ||||||||||
| 84% of Total Shell Capacity Dedicated to Customer | 155,959 | ||||||||||
Bloomfield TSA – Storage – Shell Capacity Dedicated Tanks
| Terminal | Tank | Product | Shell Capacity (in Barrels) | ||||||||
| Bloomfield | 13 | Clean Products | 30,303 | ||||||||
| Bloomfield | 14 | Clean Products | 30,097 | ||||||||
| Bloomfield | 18 | Clean Products | 56,140 | ||||||||
| Bloomfield | 20 | Clean Products | 22,176 | ||||||||
| Bloomfield | 23 | Clean Products | 40,460 | ||||||||
| Bloomfield | 24 | Clean Products | 10,354 | ||||||||
| Bloomfield | 25 | Clean Products | 10,115 | ||||||||
| Bloomfield | 32 | Clean Products | 20,000 | ||||||||
| Bloomfield | 36 | Clean Products | 56,000 | ||||||||
| Bloomfield | 44 | Clean Products | 2,100 | ||||||||
| Bloomfield | 45 | Clean Products | 5,488 | ||||||||
| Bloomfield | 42A | Slop | 400 | ||||||||
| Bloomfield | 42B | Slop | 400 | ||||||||
| Total Shell Capacity | 284,033 | ||||||||||
| 50% of Total Shell Capacity Dedicated to Customer | 142,017 | ||||||||||
El Paso TSA – Storage – Shell Capacity Dedicated Tanks
| Terminal | Tank | Product | Shell Capacity (in Barrels) | ||||||||
| El Paso | 504 | Trans-mix | 459 | ||||||||
| El Paso | 508 | Gasoline | 10,502 | ||||||||
| El Paso | 509 | Ethanol | 21,005 | ||||||||
| El Paso | 512 | Gasoline | 5,017 | ||||||||
| El Paso | 513 | Gasoline | 4,152 | ||||||||
| El Paso | 514 | Trans-mix | 1,797 | ||||||||
| El Paso | 515 | Gasoline | 3,967 | ||||||||
| El Paso | 516 | Gasoline | 4,932 | ||||||||
| El Paso | 517 | Jet | 2,552 | ||||||||
| El Paso | 518 | Jet | 1,669 | ||||||||
| El Paso | 519 | Jet | 1,337 | ||||||||
| El Paso | 520 | Gasoline | 5,358 | ||||||||
| El Paso | 521 | ULSD | 5,229 | ||||||||
| El Paso | 522 | ULSD | 5,332 | ||||||||
| El Paso | 523 | Trans-mix | 428 | ||||||||
| El Paso | 524 | Bio Diesel | 726 | ||||||||
| El Paso | 5301 | Trans-mix | 287 | ||||||||
| El Paso | 5302 | Trans-mix | 149 | ||||||||
| Total Shell Capacity | 74,898 | ||||||||||
Schedule 14.1 – Notices
| Terminal | Customer Notice Address | Terminal Owner Notice Address | ||||||
Albuquerque Bloomfield El Paso St. Paul Park | Marathon Petroleum Company LP 539 South Main Street Findlay, Ohio 45840 Attn: President E-mail: cleanproductslogistics@marathonpetroleum.com | Western Refining Terminals LLC 200 East Hardin Street Findlay, Ohio 45840 Attn: President | ||||||
Anacortes Boise Burley Carson Colton Hynes Mandan Pasco Pocatello Salt Lake City San Diego Stockton Vancouver Vinvale Wilmington | Marathon Petroleum Company LP 539 South Main Street Findlay, Ohio 45840 Attn: President E-mail: cleanproductslogistics@marathonpetroleum.com Marathon Petroleum Supply and Trading LLC 539 South Main Street Findlay, Ohio 45840 Attn: President Email: crudelogistics@marathonpetroleum.com | Tesoro Logistics Operations LLC 200 East Hardin Street Findlay, Ohio 45840 Attn: President | ||||||
Anchorage Ocean Dock Anchorage T2 Fairbanks Nikiski | Marathon Petroleum Company LP 539 South Main Street Findlay, Ohio 45840 Attn: President E-mail: cleanproductslogistics@marathonpetroleum.com | Tesoro Logistics Operations LLC 200 East Hardin Street Findlay, Ohio 45840 Attn: President Tesoro Alaska Terminals LLC 200 East Hardin Street Findlay, Ohio 45840 Attn: President | ||||||
Exhibit 10.2
SIXTH AMENDMENT TO
TERMINAL SERVICES AGREEMENT
This Sixth Amendment to Terminal Services Agreement (“Amendment”) is made and entered into as of June 30, 2023 (“Amendment Date”) with respect to each respective Terminal set forth on Schedule I, unless otherwise indicated, the party identified as “Customer” with respect to such respective Terminal as set forth on Schedule I (such party, as applicable to the respective Terminal, a “Customer”), and the party identified as “Terminal Owner” with respect to such respective Terminal as set forth on Schedule I (such party, as applicable to the respective Terminal, a “Terminal Owner”) each referred to in this Amendment as a “Party” and collectively as “Parties”.
WHEREAS, on November 1, 2020, the Parties entered into that certain Terminal Services Agreement, subsequently amended on April 30, 2021, May 30, 2021, June 30, 2021, July 31, 2021, and June 1, 2023 (collectively, the “Agreement”), pursuant to which the Parties agreed that Terminal Owner would operate the Terminal or otherwise provide certain terminal services to the Customer at the respective Terminal;
WHEREAS, Tesoro Refining & Marketing Company LLC (“TRMC”) assigned and Marathon Petroleum Supply and Trading LLC assumed all of TRMC’s right, title and interest under the Agreement pertaining to crude petroleum;
WHEREAS, TRMC, Western Refining Company LLC (formerly known as Western Refining Company L.P., “WNR”), St. Paul Park Refining Co. LLC (“SPPR”), and Tesoro Alaska Company LLC (“TAC”) assigned and Marathon Petroleum Company LP assumed all of their rights, titles, and interests under the Agreement pertaining to all commodities other than crude petroleum; and
WHEREAS, the Parties desire to amend the Agreement to remove Schedule 5.1 (d) and amend Schedule 5.1(c);
NOW, THEREFORE, in consideration of the promises and covenants in the Agreement and this Amendment and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties hereby agree as follows:
1.Schedule 5.1(c) is hereby deleted in its entirety and replaced with Schedule 5.1 (c) attached hereto.
2.Schedule 5.1(d) is hereby deleted in its entirety.
3.In all other respects, except as herein modified, the terms and provisions of the Agreement shall remain in full force and effect.
4.In the event of any conflict between the terms and provisions of this Amendment and terms and provisions of the Agreement, the terms and provisions of this Amendment shall prevail.
5.The Parties acknowledge that this Amendment may be executed utilizing an electronic signature process. By signing electronically, the Parties further acknowledge that they each have read, understand, and are bound to the terms and conditions hereof in the same manner as if the Parties had signed this Amendment with handwritten original signatures.
[Signature Page Follows]
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Anacortes
Boise
Burley
Carson
Colton
Hynes
Mandan
Pasco
Pocatello
Salt Lake City
San Diego
Stockton
Vancouver
Vinvale
Wilmington
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Marathon Petroleum Supply and Trading LLC | ||||||||||||||
| By: | /s/ Rick D. Hessling | |||||||||||||
| Name: | Rick D. Hessling | |||||||||||||
| Title: | President | |||||||||||||
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Anchorage Ocean Dock
Anchorage T2
Fairbanks
Nikiski
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Tesoro Alaska Terminals LLC | ||||||||||||||
| By: | /s/ Shawn Lyon | |||||||||||||
| Name: | Shawn Lyon | |||||||||||||
| Title: | President | |||||||||||||
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be effective as of the Amendment Date.
As to the following Terminals:
Albuquerque
Bloomfield
El Paso
St. Paul Park
Customer: | Terminal Owner: | |||||||||||||
Marathon Petroleum Company LP | Western Refining Terminals LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Brian K. Partee | Name: | Shawn Lyon | |||||||||||
| Title: | Senior Vice President | Title: | President | |||||||||||
Schedule I
Parties to Agreement per respective Terminal
| Terminal | Customer | Terminal Owner | Initial Term | Extension Period | ||||||||||
| Albuquerque | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Anacortes | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 1, 2024 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Anchorage Ocean Dock | Marathon Petroleum Company LP | Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an Extension Period by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Anchorage T2 | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC/Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Renewal Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Bloomfield | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Boise | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date – July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Burley | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Carson | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Colton | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| El Paso | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - October 16, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Fairbanks | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC/Tesoro Alaska Terminals LLC | Effective Date - September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Hynes | Marathon Petroleum Company LP Marathon Petroleum Supply and Trading LLC (for crude only) | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Mandan | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Nikiski | Marathon Petroleum Company LP | Tesoro Alaska Terminals LLC | Effective Date September 16, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 365 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. If Customer has not provided written notice of its intent to extend the Initial Term for the first Extension Period then notice may be provided no less than 90 days prior to end of Initial Term to extend the Initial Term for an additional 2 years and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Pasco | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date – July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Pocatello | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Salt Lake City | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| San Diego | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| St Paul Park | Marathon Petroleum Company LP | Western Refining Terminals LLC | Effective Date - September 15, 2026 | 2 renewal terms of 5 years each (each, an “Extension Period”) by providing written notice of its intent no less than 90 calendar days prior to the end of the Initial Term or the then-current Extension Period and such Extension Period is accepted by Terminal Owner. | ||||||||||
| Stockton | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Vancouver | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Vinvale | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - May 31, 2028 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
| Wilmington | Marathon Petroleum Company LP | Tesoro Logistics Operations LLC | Effective Date - July 31, 2026 | 1 renewal term of 1 year (the “Extension Period”) upon mutual agreement of the Parties no less than 180 calendar days prior to the end of the Initial Term | ||||||||||
Schedule 5.1(c) – Storage Fees and Monthly Storage Commitment
| Terminal Name | State | Monthly Storage Commitment (Barrels) | Storage Services Fee (per Barrel) | ||||||||
Albuquerque1 | NM | 155,959 | 0.6000 | ||||||||
| Anchorage Ocean Dock | AK | 316,000 | 1.241742 | ||||||||
| Anchorage T2 | AK | 342,000 | 1.241742 | ||||||||
Bloomfield1 | NM | 142,017 | 0.6000 | ||||||||
| El Paso | TX | 74,898 | 0.6000 | ||||||||
| Hynes – Refined products | CA | 967,662 | 1.2000 | ||||||||
Hynes – Crude/Dark Oil2 | CA | 676,910 | 1.0123 | ||||||||
| Pocatello | ID | 19,307 | 0.2800 | ||||||||
| St. Paul Park | MN | 11,808 | 0.594940 | ||||||||
| Vinvale | CA | 528,573 | 1.2000 | ||||||||
1 Terminal Owner may, but shall have no obligation to, utilize any shell capacity not being used by Customer to provide storage to third parties; provided, however, that Terminal Owner shall be required, to the extent Customer desires to utilize any then-available storage capacity, to prioritize Customer’s utilization of such storage capacity over third-party customers.
2 The Crude/Dark Oil Monthly Storage Commitment and Storage Services Fee for this Terminal will be effective through May 31, 2026, and will be subject to negotiation by the Parties thereafter; provided, however, in no event will the new Crude/Dark Oil Monthly Storage Commitment be less than 272,662 barrels per month or the Storage Services Fee be less than 75% of the current Storage Services Fee for this Terminal. If the Parties are unable to mutually agree on an adjusted Monthly Storage Commitment and Storage Services Fee by August 31, 2026, the existing Monthly Storage Commitment and Storage Services Fee for this Terminal will remain in effect through the remaining Term of this Agreement.
Exhibit 10.3
INTERCOMPANY ASSIGNMENT AGREEMENT
THIS INTERCOMPANY ASSIGNMENT AGREEMENT (“Agreement”) is made and entered into by and between:
MARATHON PETROLEUM COMPANY LP (“MPCLP”), and
MARATHON PETROLEUM SUPPLY AND TRADING LLC (“MPST”),
(together, the “Assignee Entities”);
ST. PAUL PARK REFINING CO. LLC,
TESORO ALASKA COMPANY LLC,
TESORO REFINING & MARKETING COMPANY LLC, and
WESTERN REFINING COMPANY LLC (formerly known as Western Refining Company L.P.),
(each a “Legacy Entity” and together, the “Legacy Entities” or “Assignor Entities”); and
TESORO ALASKA TERMINALS LLC,
TESORO LOGISTICS OPERATIONS LLC, and
WESTERN REFINING TERMINALS LLC,
(each a “Logistics Entity” and together, the “Logistics Entities”).
WHEREAS, the Legacy Entities and Logistics Entities entered into that certain Terminal Services Agreement dated November 1, 2020, as amended (collectively, the “Terminal Services Agreement”), pursuant to which the Logistics Entities agreed to provide certain terminal services to the Legacy Entities;
WHEREAS, the Assignee Entities and the Legacy Entities (collectively, the “Parties”) have executed this Agreement to document the assignment and assumption of the Terminal Services Agreement and the Logistics Entities do hereby consent to said assignment.
NOW, THEREFORE, the Parties agree as follows:
1.Assignment.
1.1.Effective on May 1, 2023 (the “Transition Date”), the Legacy Entities transfer, assign, grant and convey to the Assignee Entities, as applicable, all of the right, interest and benefit of the Legacy Entities in and to the Terminal Services Agreement subject to Section 1.2 below. Subject to the foregoing, the Assignee Entities accept such assignment and assume and agree to observe, perform and be bound by the conditions and obligations of the Terminal Services Agreement arising on and after the Transition Date. If applicable, any Legacy Entity will remain responsible for any obligations, including but not limited to payment obligations, incurred by that particular Legacy Entity under the Terminal Services Agreement prior to the Transition Date.
1.2.MPST only accepts assignment of the Terminal Services Agreement to the extent it pertains to crude oil and condensate and MPCLP only accepts assignment of the Terminal Services Agreement to the extent it pertains to asphalt, heavy oils, natural gas, natural gas liquids, pet coke, petrochemicals, gasoline, distillates, renewable products and renewable feedstocks. For the avoidance of doubt, commodities pertaining to the Terminal Services Agreement are listed in Schedule 1.1 (A) of the Terminal Services Agreement, as may be amended or further modified from time to time. The Parties will coordinate the allocation of rights and obligations under the Terminal Services Agreement as deemed appropriate.
2.Consent by the Logistics Entities. The Logistics Entities consent to the Legacy Entities’ assignment of the Terminal Services Agreement to the Assignee Entities as set forth in this Agreement.
3.Further Assurances. After the execution of this Agreement and as and when reasonably requested, each of the Parties will execute and deliver, or cause to be executed and delivered, all such documents and instruments and will take or cause to be taken all such further or other actions to implement or give effect to this Agreement, provided such documents, instruments or actions are consistent with the provisions of this Agreement and accepted industry practice. All such further documents, instruments or actions will be delivered or taken for no additional consideration.
4.Entire Agreement. This Agreement contains the entire agreement between the Parties with respect to the subject matter and all proposals, negotiations and representations with reference thereto are merged within.
[Signature Page Follows]
IN WITNESS WHEREOF, the Parties hereto have executed this Agreement on the dates set forth below.
Assignor Entities (Legacy Entities): | Assignee Entities: | |||||||||||||
St. Paul Park Refining Co. LLC | Marathon Petroleum Supply and Trading LLC | |||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Rick D. Hessling | |||||||||||
| Name: | Brian K. Partee | Name: | Rick D. Hessling | |||||||||||
| Title: | Vice President | Title: | President | |||||||||||
Tesoro Alaska Company LLC | Marathon Petroleum Company LP | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ Brian K. Partee | |||||||||||
| Name: | Brian K. Partee | Name: | Brian K. Partee | |||||||||||
| Title: | Vice President | Title: | Senior Vice President | |||||||||||
Tesoro Refining & Marketing Company LLC | Logistics Entities: | |||||||||||||
Tesoro Alaska Terminals LLC | ||||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ William H Wintrow | |||||||||||
| Name: | Brian K. Partee | Name: | William H Wintrow | |||||||||||
| Title: | Vice President | Title: | Director, Business Development | |||||||||||
Western Refining Company LLC | Tesoro Logistics Operations LLC | |||||||||||||
| By: | /s/ Brian K. Partee | By: | /s/ William H Wintrow | |||||||||||
| Name: | Brian K. Partee | Name: | William H Wintrow | |||||||||||
| Title: | Vice President | Title: | Director, Business Development | |||||||||||
| Western Refining Terminals LLC | ||||||||||||||
| By: | /s/ William H Wintrow | |||||||||||||
| Name: | William H Wintrow | |||||||||||||
| Title: | Director, Business Development | |||||||||||||
Exhibit 10.4
Eighth Amendment to the Third Amended and Restated Terminal Services Agreement
This Eighth Amendment to the Third Amended and Restated Terminal Services Agreement ("Amendment") is dated May 9, 2023, by and between Marathon Petroleum Company LP, a Delaware limited partnership with an address of 539 South Main Street, Findlay, Ohio 45840 ("MPC"), and MPLX Terminals LLC, a Delaware limited liability company with an address of 200 East Hardin Street, Findlay, Ohio 45840 ("Terminal Owner"). Each of MPC and Terminal Owner shall be referred to herein individually as a "Party" or collectively as the "Parties."
WHEREAS, MPC and Terminal Owner are Parties to that certain Third Amended and Restated Terminal Services Agreement, dated March 1, 2017, as amended on September 1, 2017, October 31, 2017, March 20, 2018, July 1, 2019, December 13, 2019, September 28, 2020 and May 20, 2022 (as amended, the "Agreement"); and
WHEREAS, MPC and Terminal Owner desire to amend the Agreement to update Schedule 3.1 and Schedule 5.1.
NOW, THEREFORE, in consideration of the forgoing and for other goods and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree that the foregoing recitals are incorporated herein by reference and as follows:
1.Except for the provisions of the Agreement specifically addressed in this Amendment, all other provisions of the Agreement shall remain in full force and effect.
2.Capitalized terms used but not defined in this Amendment shall have the meaning ascribed to such terms in the Agreement.
3.Schedule 3.1 of the Agreement is hereby deleted in its entirety and replaced with the attached Schedule 3.1.
4.Schedule 5.1 of the Agreement is hereby deleted in its entirety and replaced with the attached Schedule 5.1.
5.The effective date of this Amendment is June 1, 2023.
6.This Amendment constitutes the entire agreement among the Parties regarding this subject matter and may be amended or modified only by a written instrument signed by each of the Parties and supersedes any other prior agreements or understandings of the Parties relating to this subject matter and the Parties are not relying on any statement, representation, promise or inducement not expressly set forth herein.
7.This Amendment may be executed in one or more counterparts, and in both original form and one or more photocopies, each of which shall be deemed to be an original, but all of which together shall be deemed to constitute one and the same instrument.
IN WITNESS WHEREOF, the Parties hereto have caused this Amendment to be executed by their respective authorized representatives.
| Marathon Petroleum Company LP | MPLX Terminals LLC | |||||||||||||
By: MPC Investment LLC, its General Partner | ||||||||||||||
| By: | /s/ Cynthia J. Clark | By: | /s/ Shawn Lyon | |||||||||||
| Name: | Cynthia J. Clark | Name: | Shawn Lyon | |||||||||||
| Title: | V.P., CPVC North | Title: | President | |||||||||||
2
Schedule 3.1 - Terminals and Minimum Quarterly Terminal Volume Commitments
| Terminal Name | State | Region | Facility Type | Loading Hours | Gallons | RC Assets | ||||||||||||||||||||
| Lanes | Docks | Shell Capacity | ||||||||||||||||||||||||
| Bay City | MI | MW | Pipeline | 24/7 | 71,625,000 | 3 | 437,600 | |||||||||||||||||||
| Bellevue | OH | MW | Pipeline | 24/7 | 5,664,000 | 1 | - | |||||||||||||||||||
| Belton | SC | SE | Pipeline | 24/7 | 74,949,000 | 3 | 370,500 | |||||||||||||||||||
| Birmingham | AL | SE | Pipeline | 24/7 | 58,131,000 | 2 | 251,000 | |||||||||||||||||||
| Brecksville | OH | MW | Pipeline | 24/7 | 30,912,000 | 2 | 398,800 | |||||||||||||||||||
| Canton | OH | MW | Refinery | 24/7 | 159,134,000 | 6 | 48,500 | |||||||||||||||||||
| Champaign | IL | MW | Pipeline | 24/7 | 96,441,000 | 4 | 554,500 | |||||||||||||||||||
| Charleston | WV | MW | Barge | 24/7 | 36,360,000 | 2 | 1 | 165,700 | ||||||||||||||||||
| Charlotte (East) | NC | SE | Pipeline | 24/7 | 110,751,000 | 4 | 451,800 | |||||||||||||||||||
| Cincinnati | OH | MW | Barge | 24/7 | 54,021,000 | 2 | 1 | 438,700 | ||||||||||||||||||
| Columbus (East & West) | OH | MW | Pipeline | 24/7 | 197,481,000 | 4 | 749,700 | |||||||||||||||||||
| Columbus (GA) | GA | SE | Pipeline | 24/7 | 22,335,000 | 1 | 132,600 | |||||||||||||||||||
| Covington | KY | MW | Barge | 24/7 | 100,056,000 | 4 | 1 | 342,100 | ||||||||||||||||||
| Detroit | MI | MW | Refinery | 24/7 | 260,460,000 | 6 | - | |||||||||||||||||||
| Doraville | GA | SE | Pipeline | 24/7 | 52,626,000 | 2 | 217,100 | |||||||||||||||||||
| Evansville | IN | MW | Barge | 24/7 | 37,686,000 | 2 | 1 | 126,000 | ||||||||||||||||||
| Flint | MI | MW | Pipeline | 24/7 | 37,401,000 | 2 | 223,800 | |||||||||||||||||||
| Ft. Lauderdale (Eisenhower) | FL | SE | Marine | 24/7 | 112,170,000 | 4 | 1 | 559,900 | ||||||||||||||||||
| Ft. Lauderdale (Spangler) | FL | SE | Marine | 24/7 | 107,451,000 | 3 | 1 | 473,800 | ||||||||||||||||||
| Garyville | LA | SE | Refinery | 24/7 | 61,788,000 | 2 | 96,700 | |||||||||||||||||||
| Greensboro (Guilford County) | NC | SE | Pipeline | 24/7 | 78,170,000 | 414,700 | ||||||||||||||||||||
| Hammond | IN | MW | Pipeline | 24/7 | 117,831,000 | 3 | 1,193,800 | |||||||||||||||||||
| Heath | OH | MW | Pipeline | 24/7 | 49,524,000 | 2 | 11,100 | |||||||||||||||||||
| Huntington | IN | MW | Pipeline | 24/7 | 35,220,000 | 2 | 144,400 | |||||||||||||||||||
| Indianapolis | IN | MW | Pipeline | 24/7 | 64,806,000 | 3 | 951,600 | |||||||||||||||||||
| Jackson | MI | MW | Pipeline | 24/7 | 21,828,000 | 2 | 263,700 | |||||||||||||||||||
| Kenova/Catlettsburg Docks * | WV/KY | MW | Marine Docks | 24/7 | 712,500,000 | 4 | 1,398,200 | |||||||||||||||||||
| Knoxville | TN | SE | Pipeline | 24/7 | 77,520,000 | 4 | 332,800 | |||||||||||||||||||
| Lansing | MI | MW | Pipeline | 24/7 | 59,682,000 | 3 | 174,700 | |||||||||||||||||||
| Lexington | KY | MW | Pipeline | 24/7 | 79,470,000 | 3 | 205,300 | |||||||||||||||||||
| Lima | OH | MW | Pipeline | 24/7 | 92,961,000 | 2 | 819,100 | |||||||||||||||||||
| Louisville (Algonquin) | KY | MW | Barge | 24/7 | 202,890,000 | 6 | 1 | 1,215,400 | ||||||||||||||||||
| Louisville (Kramers) | KY | MW | Barge | 24/7 | 115,401,000 | 4 | 1 | 558,300 | ||||||||||||||||||
| Macon | GA | SE | Pipeline | 24/7 | 79,296,000 | 3 | 294,200 | |||||||||||||||||||
| Marietta | OH | MW | Barge | 24/7 | 46,947,000 | 3 | 2 | 170,700 | ||||||||||||||||||
| Midland | PA | MW | Barge | 24/7 | 54,573,000 | 2 | 1 | 390,400 | ||||||||||||||||||
| Montgomery | AL | SE | Pipeline | 24/7 | 53,745,000 | 2 | 191,700 | |||||||||||||||||||
| Mt. Vernon | IN | MW | Barge | 24/7 | 105,945,000 | 1 | 1 | 595,000 | ||||||||||||||||||
| Muncie | IN | MW | Pipeline | 24/7 | 42,747,000 | 2 | 232,600 | |||||||||||||||||||
| Nashville (Bordeaux) | TN | SE | Pipeline | 24/7 | 64,008,000 | 3 | 1 | 233,800 | ||||||||||||||||||
| Nashville (Downtown) | TN | SE | Barge | 24/7 | 44,289,000 | 2 | 1 | 250,800 | ||||||||||||||||||
| Nashville (51st) | TN | SE | Pipeline | 24/7 | 60,903,000 | 3 | 331,100 | |||||||||||||||||||
| Niles | MI | MW | Pipeline | 24/7 | 74,589,000 | 2 | 631,100 | |||||||||||||||||||
| North Muskegon | MI | MW | Pipeline | 24/7 | 113,175,000 | 5 | 440,200 | |||||||||||||||||||
| Oregon | OH | MW | Pipeline | 24/7 | 53,250,000 | 2 | 247,800 | |||||||||||||||||||
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| Paducah | KY | MW | Barge | 24/7 | 30,654,000 | 2 | 1 | 208,300 | ||||||||||||||||||
| Powder Springs | GA | SE | Pipeline | 24/7 | 78,300,000 | 3 | 338,300 | |||||||||||||||||||
| Robinson | IL | MW | Refinery | 24/7 | 74,736,000 | 4 | 7,300 | |||||||||||||||||||
| Romulus | MI | MW | Pipeline | 24/7 | 27,309,000 | 3 | 268,400 | |||||||||||||||||||
| Selma (Buffalo) | NC | SE | Pipeline | 24/7 | 123,750,000 | 3 | 549,000 | |||||||||||||||||||
| Selma (West Oak) | NC | SE | Pipeline | 24/7 | 99,537,000 | 4 | 355,000 | |||||||||||||||||||
| Speedway | IN | MW | Pipeline | 24/7 | 124,647,000 | 5 | 526,300 | |||||||||||||||||||
| Steubenville | OH | MW | Pipeline | 24/7 | 16,599,000 | 2 | 128,100 | |||||||||||||||||||
| Tampa | FL | SE | Marine | 24/7 | 334,203,000 | 10 | 1 | 1,231,700 | ||||||||||||||||||
| Viney Branch | KY | MW | Refinery | 24/7 | 114,474,000 | 6 | 57,100 | |||||||||||||||||||
| Youngstown | OH | MW | Pipeline | 24/7 | 28,176,000 | 2 | 131,000 | |||||||||||||||||||
* Kenova tank 23-273 idled with no expense savings and will be Terminal Owner financial responsibility to reactivate if MPC desires to bring it back into product service.
Terminal Complexes:
1.Brecksville and Canton
2.Cincinnati and Covington
3.Evansville and Mt. Vernon
4.Ft. Lauderdale (Spangler) and Ft. Lauderdale (Eisenhower)
5.Indianapolis and Speedway
6.Louisville (Kramers) and Louisville (Algonquin)
7.Nashville (Bordeaux), Nashville (Downtown) and Nashville (51st)
8.Selma (Buffalo) and Selma (West Oak)
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Schedule 5.1 – Fees
| Terminal Name | Base Throughput Fee* | Excess Throughput Fee* | ||||||
| Bay City | 0.01768976 | 0.01458831 | ||||||
| Bellevue | 0.01435857 | 0.01435857 | ||||||
| Belton | 0.01562213 | 0.01378423 | ||||||
| Birmingham | 0.01619647 | 0.01389910 | ||||||
| Brecksville | 0.03583900 | 0.01435857 | ||||||
| Canton | 0.01435857 | 0.01435857 | ||||||
| Champaign | 0.01527752 | 0.01435857 | ||||||
| Charleston | 0.02481161 | 0.01481805 | ||||||
| Charlotte (East) | 0.01585186 | 0.01412884 | ||||||
| Cincinnati | 0.03193347 | 0.01481805 | ||||||
Columbus (GA) | 0.02952122 | 0.01401396 | ||||||
Columbus (OH) | 0.01343962 | 0.01343962 | ||||||
| Covington | 0.01791949 | 0.01757490 | ||||||
Detroit LP | 0.01435857 | 0.01435857 | ||||||
| Doraville | 0.02125068 | 0.01401396 | ||||||
| Evansville | 0.02251424 | 0.01504778 | ||||||
| Flint | 0.02481161 | 0.01447344 | ||||||
| Ft. Lauderdale (Eisenhower) | 0.01929792 | 0.01447344 | ||||||
| Ft. Lauderdale (Spangler) | 0.01550725 | 0.01550725 | ||||||
| Garyville | 0.01516265 | 0.01343962 | ||||||
| Greensboro (Friendship) | 0.01378423 | 0.01378423 | ||||||
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| Terminal Name | Base Throughput Fee* | Excess Throughput Fee* | ||||||
| Hammond | 0.02079121 | 0.01355449 | ||||||
| Heath | 0.01320989 | 0.01320989 | ||||||
| Huntington | 0.02090608 | 0.01458831 | ||||||
| Indianapolis | 0.02860227 | 0.01458831 | ||||||
| Jackson | 0.04273110 | 0.01458831 | ||||||
Kenova (Catlettsburg Docks) | 0.00746646 | 0.00746646 | ||||||
| Knoxville | 0.01412884 | 0.01366936 | ||||||
| Lansing | 0.01619647 | 0.01458831 | ||||||
| Lexington | 0.01447344 | 0.01412884 | ||||||
| Lima | 0.01975739 | 0.01320989 | ||||||
| Louisville (Algonquin) | 0.02010200 | 0.01378423 | ||||||
| Louisville (Kramers) | 0.01711542 | 0.01447344 | ||||||
| Macon | 0.01527752 | 0.01343962 | ||||||
| Marietta | 0.02331832 | 0.01481805 | ||||||
| Midland | 0.02699412 | 0.01298015 | ||||||
| Montgomery | 0.01780463 | 0.01389910 | ||||||
| Mt. Vernon | 0.01826410 | 0.01263555 | ||||||
| Muncie | 0.01837897 | 0.01435857 | ||||||
| Nashville (51st) | 0.01895331 | 0.01389910 | ||||||
| Nashville (Bordeaux) | 0.01596673 | 0.01389910 | ||||||
| Nashville (Downtown) | 0.02262911 | 0.01389910 | ||||||
| Niles | 0.02056148 | 0.01424370 | ||||||
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| Terminal Name | Base Throughput Fee* | Excess Throughput Fee* | ||||||
| North Muskegon | 0.01458831 | 0.01458831 | ||||||
| Oregon | 0.01849383 | 0.01435857 | ||||||
| Paducah | 0.02929148 | 0.01435857 | ||||||
| Powder Springs | 0.01677081 | 0.01401396 | ||||||
| Robinson | 0.01504778 | 0.01401396 | ||||||
| Romulus | 0.04008913 | 0.01470318 | ||||||
| Selma (Buffalo) | 0.01401396 | 0.01401396 | ||||||
| Selma (West Oak) | 0.01401396 | 0.01401396 | ||||||
| Speedway | 0.01458831 | 0.01458831 | ||||||
| Steubenville | 0.03457544 | 0.01424370 | ||||||
| Tampa | 0.01573700 | 0.01458831 | ||||||
| Viney Branch | 0.01447344 | 0.01447344 | ||||||
| Youngstown | 0.02504135 | 0.01389910 | ||||||
*The table above reflects the fees effective as of January 1, 2023, as adjusted per Section 5.3.
Marine Docks
Kenova/Catlettsburg Docks includes Kenova Light Product, and Catlettsburg Crude, Heavy Oil, and
Light Oil Docks
Kenova/Catlettsburg Docks - $2,871,714 per month (reflects monthly fee effective as January 1, 2023, as adjusted per Section 5.3).
Butane/Natural Gasoline/Pentane Blending
A)Facilities with Third Party Licensed Blending Technology
From and after July 1, 2019, at facilities at which Energy Transfer Partners LP ("ETP") licenses blending technology to MPC, Terminal Owner's fee for performing the butane blending service shall be calculated as follows:
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Ninety-five percent (95%) of the difference between the Daily Gasoline Value (defined below) and the Daily Butane Value (defined below). Expressed as a formula, the Butane Blending Service Fee is:
Butane Blending Service Fee = (DGV-DBV)* 95%
NOTE: Terminal Owner will reflect an Annual True-Up, as defined in Section 4 of this Schedule 5.1, as a separate line item on any monthly invoices submitted pursuant to this Agreement.
Definitions:
1. Daily Gasoline Value ("DGV"): Expressed as a formula:
DGV = (GB)*(GPV+TF)
GB: number of Gallons of butane blended on a given day at the terminal site.
GPV: daily gasoline posted value per Gallon.
TF: the transportation fee for moving spot purchased gasoline to the terminal for the gasoline grade in which the butane is blended.
a. GPV is calculated by location as follows:
Location | Market | GPV Price Calculation | ||||||
Bay City | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Charlotte East | Gulf Coast | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Lansing | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Nashville 51st | Gulf Coast | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Selma Buffalo | Gulf Coast | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Selma Oak | Gulf Coast | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Speedway | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
North Muskegon | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Tampa | Gulf Coast | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Indianapolis | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
Lima | Chicago | Daily posted Argus 85 CBOB and 91 PREM spot prices | ||||||
b. TF is the avoided MPC cost of transporting one Gallon of gasoline (in the most cost effective method possible) to a terminal blending location, as verified and
8
provided by MPC's Supply Distribution & Planning - Light Products Project Analysis organization.
2. Daily Butane Value ("DBV"): the daily agreed upon butane purchase price ("BPP") from ETP plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane gallons blended ("GB"). Expressed as a formula:
DBV = (GB)*(BPP+DRV)
Bay City DBV = (GB)*(BPP+1/2DRV)
a. DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually or the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, postings for prior year’s RINs will be used up to the maximum allowable percentage.
3. Profit Sharing Payment: For each calendar month, a Profit Sharing Payment (“PSP”) is paid by ETP to MPC for volumes blended at the Bay City terminal. The PSP is calculated as the volume of gallons blended (“GB”) at Bay City in such month multiplied by fifty percent multiplied by the following value: (A) the volume weighted daily average of the high and low assessments of Argus posted Chicago Cycle 1 gasoline price (85 CBOB) minus (B) the volume weighted daily average of the high and low assessments of the OPIS posted Mt. Belvieu TET normal butane price minus (C) the average supply cost.
Fee calculations pursuant to this Schedule 5.1 for butane blending services completed prior to July 1, 2019 shall not be affected by changes in the foregoing formulas.
4. Annual True-Up: This cost or revenue is intended to cover changes in the estimated vs actual transportation costs, half of shared maintenance expenses, and estimated vs actual butane purchase costs. The cost or revenue is calculated ETP. MPC will pass ninety-five percent (95%) of this to Terminal Owner.
B)Facilities Without Third Party Blending Technology
From and after September 1, 2018, at facilities at which no third party licensed blending technology is utilized, Terminal Owner’s fee for performing the butane or pentane blending service shall be calculated as follows:
Ninety-five percent (95%) of the difference between the Tank Daily Gasoline Value (defined below) and the Tank Daily Butane Value (defined below). Expressed as a formula, the Tank Butane Blending Service Fee is:
Tank Butane Blending Service Fee = (TDGV-TDBV)* 95%
Or
Ninety-five percent (95%) of the difference between the Tank Daily Gasoline Value (defined below) and the Tank Daily Pentane Value (defined below). Expressed as a formula, the Tank Pentane Blending Service Fee is:
9
Tank Pentane Blending Service Fee = (TDGV-TDPV)* 95%
Definitions:
1.Tank Daily Gasoline Value (“TDGV”): Expressed as a formula:
TDGV = (GB)*(GPV+TF)
GB: number of Gallons of butane blended on a given day at the terminal site.
GPV: daily gasoline posted value per gallon.
TF: the avoided transportation fee for moving spot purchased gasoline to the terminal for the gasoline grade in which the butane is blended.
a.GPV is calculated by location using the daily posted average Argus 85 CBOB or Argus PREM spot prices for the respective blend and market derived from Schedule 3.1.
2.Tank Daily Butane Value (“TDBV”): the daily agreed upon tank butane purchase price (“TBPP”) from supplier, plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane Gallons blended (“GB”). Expressed as a formula:
TDBV = (GB)*(TBPP+DRV+TC)
a.TC is the trucking cost of transporting one Gallon of butane (in the most cost effective method possible) to a terminal blending location.
b.DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually to the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, posting for prior year’s RINs will be used up to the maximum allowable percentage.
3.Tank Daily Pentane Value (“TDPV”): the daily agreed upon tank pentane purchase price (“TPPP”) from supplier, plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane Gallons blended (“GB”). Expressed as a formula:
TDPV = (GB) * (TPPP + DRV + TC)
a.TC is the trucking costs of transporting one Gallon of pentane (in the most cost-effective manner) to a terminal blending location.
b.DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually or the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, postings for the prior year’s RINs will be used up to the maximum allowable percentage.
4.In the event MPC requests a butane skid for temporary use at an MPC owned terminal(s), MPC shall pay an MPLX Tank Butane Blending Equipment Service Fee equal to 5% of the blending value. Expressed as a formula:
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a.MPLX Tank Butane Blending Equipment Service Fee = (TDGV-TDBV)* 5%.
5.Annual Adjustment to Revenue: This cost or revenue is intended to cover changes in the estimated vs actual transportation costs. Annually during the month of April, MPC will issue an adjustment of revenue to MPLX. This adjustment will be the result in changes of actual vs previously estimated trucking costs associated with delivery of butane to the terminals for the previous April- March.
C)Kenova Blending
From and after October 31st, 2019, at the Kenova, WV terminal the Terminal Owner’s fee for performing in-line or barge loading blending service shall be calculated as follows:
Ninety-five percent (95%) of the difference between the Marathon Daily Gasoline Value (defined below) and the Marathon Daily Butane Value (defined below) or the Marathon Daily Pentane Value (defined below). Expressed as a formula the Inline or Barge Blending Service Fee is:
Inline or Barge Blending Service Fee = (MDGV – MDBV) * 0.95
Or
Inline or Barge Blending Service Fee = (MDGV – MDPV) * 0.95
Definitions:
1.Marathon Daily Gasoline Value (“MDGV”): Expressed as a formula:
MDGV = (GB) * (GPV + KTF)
GB: Number of Gallons of butane/pentane blended on a given day at the terminal site.
GPV: daily gasoline posted value per Gallon
KTF: the additional transportation costs for moving the gasoline barrel produced through butane or pentane blending to the terminal of sale
a.GPV is calculated by the location using the daily posted averages of either Argus 85 CBOB or Argus Prem spot prices for the respective blend and market derived from Schedule 3.1
2.Marathon Daily Butane Value (“MDBV”): the daily agreed upon Marathon butane purchase price (“MBPP”) from supplier, plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane Gallons blended (“GB”). Expressed as a formula:
MDBV = (GB) * (MBPP + DRV + TC)
a.TC is the trucking costs of transporting one Gallon of butane (in the most cost-effective manner) to a terminal blending location.
b.DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually or the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, postings for the prior year’s RINs will be used up to the maximum allowable percentage.
11
3.Marathon Daily Pentane Value (“MDPV”): the daily agreed upon Marathon pentane purchase price (“MPPP”) from supplier, plus the total daily RIN value (“DRV”), multiplied by the daily total number of butane Gallons blended (“GB”). Expressed as a formula:
MDPV = (GB) * (MPPP + DRV + TC)
a.TC is the trucking costs of transporting one Gallon of pentane (in the most cost-effective manner) to a terminal blending location.
b.DRV will be determined by using the percentage of each type of RINs specified by the Renewable Fuel Standard Program updated annually or the most recent requirements and will be adjusted retroactively for any difference between the requirements at the time of the calculation and the requirements contained in a final rule establishing Renewable Volume Obligations for the year. OPIS daily posting for the respective RINs pricing will be used. In order to minimize the daily average RINs Cost, postings for the prior year’s RINs will be used up to the maximum allowable percentage.
D) Butane Blending into Natural Gasoline at Facilities Without Third Party Licensed Blending Technology
a. Butane Blending into Natural Gasoline Project Service Fee: Prior to MPC requesting Terminal Owner to provide natural gasoline blending services at a Terminal that does not have butane blending into natural gasoline service capabilities, MPC will pay a one-time fee to Terminal Owner as reimbursement for the project capital costs to be incurred by a Terminal to enable such Terminal to provide butane blending into natural gasoline services, as well as an additional charge of 15% of such project capital costs. Prior to any Terminal incurring any project capital costs to be able to provide butane blending into natural gasoline services for MPC, the Parties will agree upon the Butane Blending into Natural Gasoline Project Services Fee for each Terminal providing such services.
b. Butane Blending into Natural Gasoline Services Fee: From and after August 20th, 2019 at any Terminal with no third-party licensed blending technology utilized, Terminal Owner’s fee for performing butane blending into natural gasoline services shall be calculated as follows, expressed as a formula:
Natural Gas Blending Services Fee = $1.58 * the number of barrels of butane blended into natural gasoline
Ethanol Denaturing
$0.02 per Gallon of undenatured ethanol.
Unit Train Ethanol Receipts
Beginning on January 15, 2017 and continuing thereafter for so long as the Master Terminal Services Agreement by and between MPC and ECO Energy Distribution Services, LLC dated October 19, 2015 (the "ECO Agreement") has not terminated, been cancelled or otherwise expired pursuant to its terms or agreement of the parties thereto, each of the following shall apply:
12
1. MPC shall pay Terminal Owner $0.0135 per Gallon for Unit Train Ethanol Receipts; provided that the invoice for the month ending March 31 of each year (or upon termination of the ECO Agreement, prorated according to the time of such termination) shall include an additional fee of $0.0135 per Gallon of Unit Train Ethanol Receipts that are less than 111,360,000 Gallons for the 12-month period ending on March 31 of the same year (prorated for the time period between January 15, 2017 through March 31, 2017. The $0.0135 per Gallon fee set forth in this Section shall be adjusted at the time of and in an amount equal to any adjustment to the Throughput Fees (as defined in the ECO Agreement) pursuant to Section 6.l(b) of the ECO Agreement, as may be amended from time to time.
At the end of each Calendar Quarter, Terminal Owner shall credit MPC on the monthly invoice (or upon termination of the ECO Agreement, prorated according to the time of such termination) an amount equal to the sum of (a) the Base Throughput Fee for Selma (Buffalo) set forth in Schedule 5.1 (as adjusted) multiplied by the volume (in Gallons) of ethanol redelivered by truck from the Selma (Buffalo) Terminal to the Selma (West Oak) Terminals during such Calendar Quarter; and (b) the Base Throughput Fee for Selma (Buffalo) set forth in Schedule 5.1 (as adjusted) multiplied by the volume (in Gallons) of ethanol redelivered per MPC's direction from the Selma (Buffalo) Terminal into trucks for ECO during such Calendar Quarter.
Ethanol Excess Volume Value Capture
MPC will pay Terminal Owner fees as calculated herein for EV at Terminals where sales volume is made on a temperature corrected basis.
The value will be calculated via the following method: Multiply the volume by the price per the calculations described in the following two paragraphs.
The volume will be calculated via the following method: The American Petroleum Institute’s Manual of Petroleum Measurement Standards Chapter 11.3.4 “Miscellaneous Hydrocarbon Properties – Denatured Ethanol and Gasoline Blend Densities and Volume Correction Factors” (“Chapter 11.3.4”) provides data-based equations for Blends of Gasoline and Ethanol (“BGE”). Chapter 11.3.4 addresses excess volumes of gasohol (“EV”) created when gasoline and ethanol components are blended together. EV for truck rack throughput at Terminals equipped with Terminal Automation Software (TAS) will be calculated using the equation in Chapter 11.3.4 performed by TAS for any BGE. The TAS will be programmed to calculate EV by multiplying these BGE volumes by the correction factors as calculated using the equation from Chapter 11.3.4. This process of crediting Terminal Owner with the EV based on the technology Terminal Owner installed and maintains at its Terminals is known as “Ethanol Excess Volume Value Capture.”
The price will be calculated via the following method: Each Terminal is assigned to the CHICAGO (Midwest-designated as ‘MW’) or US GULF COAST (Southeast-designated as ‘SE’) region based on Schedule 3.1. EV credited to Terminal Owner will be valued using the non-weighted monthly average ARGUS 85 Assessment MID CBOB price for given market based on the location of the Terminal. The Midwest (‘MW’) will be using West Shore and Gulf Coast (‘SE’) will be using Pasadena posted pricing.
13
Exhibit 31.1
CERTIFICATION PURSUANT TO SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
I, Michael J. Hennigan, certify that:
1.I have reviewed this report on Form 10-Q of MPLX LP;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: August 1, 2023 | /s/ Michael J. Hennigan | |||||||
| Michael J. Hennigan | ||||||||
| Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) | ||||||||
Exhibit 31.2
CERTIFICATION PURSUANT TO SECTION 302 OF
THE SARBANES-OXLEY ACT OF 2002
I, John J. Quaid, certify that:
1.I have reviewed this report on Form 10-Q of MPLX LP;
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
(a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
(b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
(c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
(a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
(b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
| Date: August 1, 2023 | /s/ John J. Quaid | |||||||
| John J. Quaid | ||||||||
| Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) | ||||||||
Exhibit 32.1
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of MPLX LP (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Hennigan, Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
| Date: August 1, 2023 | ||||||||
| /s/ Michael J. Hennigan | ||||||||
| Michael J. Hennigan | ||||||||
| Chairman of the Board, President and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) | ||||||||
Exhibit 32.2
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
In connection with the Quarterly Report of MPLX LP (the “Partnership”) on Form 10-Q for the quarter ended June 30, 2023 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John J. Quaid, Executive Vice President and Chief Financial Officer of MPLX GP LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:
(1)The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
| Date: August 1, 2023 | ||||||||
| /s/ John J. Quaid | ||||||||
| John J. Quaid | ||||||||
| Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP) | ||||||||