UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________________________________
FORM 10-Q
_____________________________________________
(Mark One)
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x(Mark One) |
☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended quarterly period ended September 30, 2017
2023
OR
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¨☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 001-35714
_____________________________________________
MPLX LP
(Exact name of registrant as specified in its charter)
_____________________________________________
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Delaware | Delaware | | | 27-0005456 |
(State or other jurisdiction of incorporation or organization)
| | (I.R.S. Employer Identification No.)
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200 E. Hardin Street, Findlay, Ohio | Findlay, | Ohio | | 45840 | |
(Address of principal executive offices) | | (Zip code) | |
(419) 421-2414
(Registrant’s telephone number, including area code)
_____________________________________________
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Securities Registered pursuant to Section 12(b) of the Act |
Title of each class | Trading symbol(s) | Name of each exchange on which registered |
Common Units Representing Limited Partnership Interests | MPLX | New York Stock Exchange |
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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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.
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Large accelerated filer | x | | Accelerated filer | ¨☐ | | Non-accelerated filer | ☐ |
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Non-accelerated filer | ¨ (Do not check if a smaller reporting company)
| 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 407,066,3201,001,217,044 common units and 8,307,473 general partner units outstanding atas of October 27, 2017.
MPLX LP
Form 10-Q
Quarter Ended September 30, 2017
INDEX
Table of Contents
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Item 2. Unregistered Sales of Equity Securities5. | | |
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Unless otherwise stated or the context otherwise requires,indicates, all references in this reportForm 10-Q to “MPLX LP,” “MPLX,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”), Hardin Street Marine LLC (“HSM”), Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”). We have partial ownership interests in a number of joint venture legal entities, including MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”), MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Sherwood Midstream LLC (“Sherwood Midstream”), Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), MarEn Bakken Company, LLC (“MarEn Bakken”), Johnston County Terminal, LLC (“Johnston Terminal”), Guilford County Terminal Company, LLC (“Guilford Terminal”), LOOP LLC (“LOOP”), LOCAP LLC (“LOCAP”), Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”) and Explorer Pipeline Company (“Explorer”).consolidated subsidiaries. References to “MPC”our sponsor and customer, “MPC,” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. Unless otherwise specified, references to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the dates of their respective acquisitions effective January 1, 2014 for HSM, January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.
Glossary of Terms
The abbreviations, acronyms and industry technology used in this report are defined as follows.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 |
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| |
ATM Program | A continuous offering, or at-the-market program, by which the Partnership may offer common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings |
Bbl | Barrels |
Bcf/d | One billion cubic feet of natural gas per day |
Btu | One British thermal unit, an energy measurement |
Condensate | A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions |
DCF (a non-GAAP financial measure) | Distributable Cash Flow |
Dth/d | Dekatherms per day |
EBITDA (a non-GAAP financial measure) | Earnings Before Interest, Taxes, Depreciation and Amortization |
EPA | United States Environmental Protection Agency |
FASB | |
FASB | Financial Accounting Standards Board |
GAAPFCF (a non-GAAP financial measure) | Free Cash Flow |
GAAP | Accounting principles generally accepted in the United States of America |
Gal | Gallon |
Gal/d | Gallons per day |
IDR | Incentive distribution right |
Initial OfferingG&P | Initial public offering on October 31, 2012Gathering and Processing segment |
LIBORL&S | London Interbank Offered RateLogistics and Storage segment |
MarkWest Mergermbpd | On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners, L.P. |
mbpd | Thousand barrels per day |
MMBtu | |
MMBtu | One million British thermal units, an energy measurement |
MMcf/d | One million cubic feet of natural gas per day |
Net operating margin (a non-GAAP financial measure)NGL | Segment revenues, less segment purchased product costs, less realized derivative gains (losses) related to purchased product costs |
NGL | Natural gas liquids, such as ethane, propane, butanes and natural gasoline |
NYSE | New York Stock Exchange |
OTC | Over-the-Counter |
Partnership Agreement | Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016, as amended |
Predecessor | Collectively:
- HSM’s related assets, liabilities and results of operations prior to the date of its acquisition, March 31, 2016, effective January 1, 2015.
- HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the date of the acquisition, March 1, 2017, effective January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.
|
Realized derivative gain/loss | The gain or loss recognized when a derivative matures or is settled |
SEC | United StatesU.S. Securities and Exchange Commission |
SMRSOFR | Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, TexasSecured Overnight Financing Rate |
Unrealized derivative gain/lossVIE | The gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling |
VIE | Variable interest entity |
WTI | West Texas Intermediate |
| |
Part I—Financial Information
Item 1. Financial Statements
MPLX LP
Consolidated Statements of Income (Unaudited) | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions, except per unit data) | 2023 | | 2022 | | 2023 | | 2022 |
Revenues and other income: | | | | | | | |
Service revenue | $ | 641 | | | $ | 627 | | | $ | 1,881 | | | $ | 1,758 | |
Service revenue - related parties | 1,038 | | | 948 | | | 2,962 | | | 2,801 | |
Service revenue - product related | 75 | | | 83 | | | 214 | | | 324 | |
Rental income | 61 | | | 75 | | | 181 | | | 268 | |
Rental income - related parties | 207 | | | 201 | | | 612 | | | 564 | |
Product sales | 478 | | | 617 | | | 1,274 | | | 1,812 | |
Product sales - related parties | 51 | | | 46 | | | 155 | | | 142 | |
| | | | | | | |
Sales-type lease revenue | 34 | | | 28 | | | 101 | | | 28 | |
Sales-type lease revenue - related parties | 129 | | | 118 | | | 379 | | | 343 | |
Income from equity method investments | 159 | | | 125 | | | 438 | | | 335 | |
Other income | 7 | | | 505 | | | 28 | | | 494 | |
Other income - related parties | 32 | | | 28 | | | 90 | | | 82 | |
Total revenues and other income | 2,912 | | | 3,401 | | | 8,315 | | | 8,951 | |
Costs and expenses: | | | | | | | |
Cost of revenues (excludes items below) | 367 | | | 371 | | | 1,023 | | | 981 | |
Purchased product costs | 474 | | | 540 | | | 1,234 | | | 1,670 | |
Rental cost of sales | 20 | | | 22 | | | 60 | | | 101 | |
Rental cost of sales - related parties | 8 | | | 10 | | | 24 | | | 44 | |
Purchases - related parties | 442 | | | 364 | | | 1,160 | | | 1,034 | |
Depreciation and amortization | 301 | | | 302 | | | 907 | | | 925 | |
| | | | | | | |
General and administrative expenses | 102 | | | 88 | | | 280 | | | 248 | |
| | | | | | | |
Other taxes | 44 | | | 30 | | | 102 | | | 97 | |
Total costs and expenses | 1,758 | | | 1,727 | | | 4,790 | | | 5,100 | |
Income from operations | 1,154 | | | 1,674 | | | 3,525 | | | 3,851 | |
Related-party interest and other financial costs | — | | | — | | | — | | | 5 | |
Interest expense, net of amounts capitalized | 223 | | | 217 | | | 673 | | | 627 | |
Other financial costs, net | 2 | | | 19 | | | 28 | | | 59 | |
Income before income taxes | 929 | | | 1,438 | | | 2,824 | | | 3,160 | |
Provision for income taxes | 1 | | | 1 | | | 2 | | | 6 | |
Net income | 928 | | | 1,437 | | | 2,822 | | | 3,154 | |
Less: Net income attributable to noncontrolling interests | 10 | | | 9 | | | 28 | | | 26 | |
Net income attributable to MPLX LP | 918 | | | 1,428 | | | 2,794 | | | 3,128 | |
Less: Series A preferred unitholders interest in net income | 25 | | | 23 | | | 71 | | | 65 | |
Less: Series B preferred unitholders interest in net income | — | | | 10 | | | 5 | | | 31 | |
Limited partners' interest in net income attributable to MPLX LP | $ | 893 | | | $ | 1,395 | | | $ | 2,718 | | | $ | 3,032 | |
Per Unit Data (See Note 6) | | | | | | | |
Net income attributable to MPLX LP per limited partner unit: | | | | | | |
Common - basic | $ | 0.89 | | | $ | 1.36 | | | $ | 2.70 | | | $ | 2.97 | |
Common - diluted | $ | 0.89 | | | $ | 1.36 | | | $ | 2.70 | | | $ | 2.97 | |
Weighted average limited partner units outstanding: | | | | | | | |
Common - basic | 1,001 | | | 1,010 | | | 1,001 | | | 1,012 | |
Common - diluted | 1,001 | | | 1,011 | | | 1,001 | | | 1,013 | |
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| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions, except per unit data) | 2017 | | 2016(1) | | 2017 | | 2016(1) |
Revenues and other income: | | | | | | | |
Service revenue | $ | 299 |
| | $ | 250 |
| | $ | 845 |
| | $ | 712 |
|
Service revenue - related parties | 276 |
| | 253 |
| | 801 |
| | 676 |
|
Rental income | 69 |
| | 77 |
| | 208 |
| | 218 |
|
Rental income - related parties | 70 |
| | 68 |
| | 207 |
| | 172 |
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Product sales | 217 |
| | 157 |
| | 611 |
| | 394 |
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Product sales - related parties | 2 |
| | 2 |
| | 6 |
| | 8 |
|
Gain on sale of assets | — |
| | 1 |
| | 1 |
| | 1 |
|
Income (loss) from equity method investments | 23 |
| | 6 |
| | 29 |
| | (72 | ) |
Other income | 2 |
| | 2 |
| | 5 |
| | 5 |
|
Other income - related parties | 22 |
| | 22 |
| | 69 |
| | 67 |
|
Total revenues and other income | 980 |
| | 838 |
| | 2,782 |
| | 2,181 |
|
Costs and expenses: | | | | | | | |
Cost of revenues (excludes items below) | 129 |
| | 122 |
| | 381 |
| | 329 |
|
Purchased product costs | 170 |
| | 117 |
| | 441 |
| | 310 |
|
Rental cost of sales | 19 |
| | 13 |
| | 44 |
| | 42 |
|
Rental cost of sales - related parties | — |
| | — |
| | 1 |
| | 1 |
|
Purchases - related parties | 114 |
| | 109 |
| | 330 |
| | 286 |
|
Depreciation and amortization | 164 |
| | 151 |
| | 515 |
| | 438 |
|
Impairment expense | — |
| | — |
| | — |
| | 130 |
|
General and administrative expenses | 59 |
| | 56 |
| | 174 |
| | 172 |
|
Other taxes | 14 |
| | 12 |
| | 40 |
| | 37 |
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Total costs and expenses | 669 |
| | 580 |
| | 1,926 |
| | 1,745 |
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Income from operations | 311 |
| | 258 |
| | 856 |
| | 436 |
|
Related party interest and other financial costs | 1 |
| | — |
| | 1 |
| | 1 |
|
Interest expense (net of amounts capitalized of $6 million, $7 million, $24 million and $21 million, respectively) | 77 |
| | 51 |
| | 217 |
| | 158 |
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Other financial costs | 15 |
| | 13 |
| | 40 |
| | 37 |
|
Income before income taxes | 218 |
| | 194 |
| | 598 |
| | 240 |
|
Provision (benefit) for income taxes | 1 |
| | — |
| | 3 |
| | (12 | ) |
Net income | 217 |
| | 194 |
| | 595 |
| | 252 |
|
Less: Net income attributable to noncontrolling interests | 1 |
| | 2 |
| | 3 |
| | 3 |
|
Less: Net income attributable to Predecessor | — |
| | 51 |
| | 36 |
| | 149 |
|
Net income attributable to MPLX LP | 216 |
| | 141 |
| | 556 |
| | 100 |
|
Less: Preferred unit distributions | 16 |
| | 16 |
| | 49 |
| | 25 |
|
Less: General partner’s interest in net income attributable to MPLX LP | 86 |
| | 51 |
| | 222 |
| | 136 |
|
Limited partners’ interest in net income (loss) attributable to MPLX LP | $ | 114 |
| | $ | 74 |
| | $ | 285 |
| | $ | (61 | ) |
Per Unit Data (See Note 6) | | | | | | | |
Net income (loss) attributable to MPLX LP per limited partner unit: | | | | | | | |
Common - basic | $ | 0.29 |
| | $ | 0.22 |
| | $ | 0.75 |
| | $ | (0.19 | ) |
Common - diluted | 0.29 |
| | 0.21 |
| | 0.75 |
| | (0.19 | ) |
Weighted average limited partner units outstanding: | | | | | | | |
Common - basic | 394 |
| | 341 |
| | 378 |
| | 324 |
|
Common - diluted | 395 |
| | 346 |
| | 381 |
| | 324 |
|
Cash distributions declared per limited partner common unit | $ | 0.5875 |
| | $ | 0.5150 |
| | $ | 1.6900 |
| | $ | 1.5300 |
|
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(1) | Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3. |
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Balance Sheets (Unaudited)
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
Assets | | | |
Current assets: | | | |
Cash and cash equivalents | $ | 3 |
| | $ | 234 |
|
Receivables, net | 320 |
| | 299 |
|
Receivables - related parties | 152 |
| | 247 |
|
Inventories | 64 |
| | 55 |
|
Other current assets | 32 |
| | 33 |
|
Total current assets | 571 |
| | 868 |
|
Equity method investments | 3,997 |
| | 2,471 |
|
Property, plant and equipment, net | 11,922 |
| | 11,408 |
|
Intangibles, net | 463 |
| | 492 |
|
Goodwill | 2,245 |
| | 2,245 |
|
Long-term receivables - related parties | 18 |
| | 11 |
|
Other noncurrent assets | 22 |
| | 14 |
|
Total assets | $ | 19,238 |
| | $ | 17,509 |
|
Liabilities | | | |
Current liabilities: | | | |
Accounts payable | $ | 152 |
| | $ | 140 |
|
Accrued liabilities | 202 |
| | 232 |
|
Payables - related parties | 317 |
| | 87 |
|
Deferred revenue | 3 |
| | 2 |
|
Deferred revenue - related parties | 42 |
| | 38 |
|
Accrued property, plant and equipment | 183 |
| | 146 |
|
Accrued taxes | 44 |
| | 38 |
|
Accrued interest payable | 64 |
| | 53 |
|
Other current liabilities | 41 |
| | 27 |
|
Total current liabilities | 1,048 |
| | 763 |
|
Long-term deferred revenue | 34 |
| | 12 |
|
Long-term deferred revenue - related parties | 40 |
| | 19 |
|
Long-term debt | 6,848 |
| | 4,422 |
|
Deferred income taxes | 7 |
| | 6 |
|
Deferred credits and other liabilities | 175 |
| | 177 |
|
Total liabilities | 8,152 |
| | 5,399 |
|
Commitments and contingencies (see Note 17) |
| |
|
Redeemable preferred units | 1,000 |
| | 1,000 |
|
Equity | | | |
Common unitholders - public (289 million and 271 million units issued and outstanding) | 8,457 |
| | 8,086 |
|
Class B unitholders (0 million and 4 million units issued and outstanding) | — |
| | 133 |
|
Common unitholder - MPC (95 million and 86 million units issued and outstanding) | 1,302 |
| | 1,069 |
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Common unitholder - GP (23 million and 0 units issued and outstanding) | 822 |
| | — |
|
General partner - MPC (8 million and 7 million units issued and outstanding) | (626 | ) | | 1,013 |
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Equity of Predecessor | — |
| | 791 |
|
Accumulated other comprehensive loss | (14 | ) | | — |
|
Total MPLX LP partners’ capital | 9,941 |
| | 11,092 |
|
Noncontrolling interests | 145 |
| | 18 |
|
Total equity | 10,086 |
| | 11,110 |
|
Total liabilities, preferred units and equity | $ | 19,238 |
| | $ | 17,509 |
|
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of Cash FlowsComprehensive Income (Unaudited) |
| | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2017 | | 2016(1) |
(Decrease) increase in cash and cash equivalents | | | |
Operating activities: | | | |
Net income | $ | 595 |
| | $ | 252 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
Amortization of deferred financing costs | 38 |
| | 34 |
|
Depreciation and amortization | 515 |
| | 438 |
|
Impairment expense | — |
| | 130 |
|
Deferred income taxes | 2 |
| | (16 | ) |
Asset retirement expenditures | (2 | ) | | (4 | ) |
Gain on disposal of assets | (1 | ) | | (1 | ) |
(Income) loss from equity method investments | (29 | ) | | 72 |
|
Distributions from unconsolidated affiliates | 136 |
| | 111 |
|
Changes in: | | | |
Current receivables | (20 | ) | | (43 | ) |
Inventories | (3 | ) | | (4 | ) |
Fair value of derivatives | (3 | ) | | 28 |
|
Current accounts payable and accrued liabilities | 6 |
| | 64 |
|
Receivables from / liabilities to related parties | 61 |
| | (104 | ) |
All other, net | 43 |
| | 18 |
|
Net cash provided by operating activities | 1,338 |
| | 975 |
|
Investing activities: | | | |
Additions to property, plant and equipment | (1,004 | ) | | (943 | ) |
Acquisitions, net of cash acquired | (249 | ) | | — |
|
Disposal of assets | 4 |
| | — |
|
Investments - net related party loans | 80 |
| | 103 |
|
Investments in unconsolidated affiliates | (690 | ) | | (56 | ) |
Distributions from unconsolidated affiliates - return of capital | 24 |
| | — |
|
All other, net | (2 | ) | | 4 |
|
Net cash used in investing activities | (1,837 | ) | | (892 | ) |
Financing activities: | | | |
Long-term debt - borrowings | 2,661 |
| | 434 |
|
- repayments | (251 | ) | | (1,312 | ) |
Related party debt - borrowings | 829 |
| | 2,215 |
|
- repayments | (627 | ) | | (2,223 | ) |
Debt issuance costs | (25 | ) | | — |
|
Net proceeds from equity offerings | 483 |
| | 510 |
|
Issuance of redeemable preferred units | — |
| | 984 |
|
Distribution to MPC for acquisition | (1,931 | ) | | — |
|
Distributions to preferred unitholders | (49 | ) | | (9 | ) |
Distributions to unitholders and general partner | (800 | ) | | (612 | ) |
Distributions to noncontrolling interests | (4 | ) | | (3 | ) |
Contributions from noncontrolling interests | 128 |
| | 4 |
|
Consideration payment to Class B unitholders | (25 | ) | | (25 | ) |
All other, net | (8 | ) | | (2 | ) |
Contribution from MPC | — |
| | 225 |
|
Distributions to MPC from Predecessor | (113 | ) | | (104 | ) |
Net cash provided by financing activities | 268 |
| | 82 |
|
Net (decrease) increase in cash and cash equivalents | (231 | ) | | 165 |
|
Cash and cash equivalents at beginning of period | 234 |
| | 43 |
|
Cash and cash equivalents at end of period | $ | 3 |
| | $ | 208 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
Net income | $ | 928 | | | $ | 1,437 | | | $ | 2,822 | | | $ | 3,154 | |
Other comprehensive income, net of tax: | | | | | | | |
Remeasurements of pension and other postretirement benefits related to equity method investments, net of tax | — | | | — | | | 4 | | | 9 | |
Comprehensive income | 928 | | | 1,437 | | | 2,826 | | | 3,163 | |
Less comprehensive income attributable to: | | | | | | | |
Noncontrolling interests | 10 | | | 9 | | | 28 | | | 26 | |
Comprehensive income attributable to MPLX LP | $ | 918 | | | $ | 1,428 | | | $ | 2,798 | | | $ | 3,137 | |
| |
(1) | Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3. |
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of EquityBalance Sheets (Unaudited)
| | | | | | | | | | | |
(In millions) | September 30, 2023 | | December 31, 2022 |
Assets | | | |
Cash and cash equivalents | $ | 960 | | | $ | 238 | |
| | | |
Receivables, net | 833 | | | 737 | |
Current assets - related parties | 759 | | | 729 | |
Inventories | 154 | | | 148 | |
| | | |
Other current assets | 30 | | | 53 | |
Total current assets | 2,736 | | | 1,905 | |
Equity method investments | 4,099 | | | 4,095 | |
Property, plant and equipment, net | 18,620 | | | 18,848 | |
Intangibles, net | 609 | | | 705 | |
Goodwill | 7,645 | | | 7,645 | |
Right of use assets, net | 271 | | | 283 | |
Noncurrent assets - related parties | 1,174 | | | 1,225 | |
Other noncurrent assets | 966 | | | 959 | |
Total assets | 36,120 | | | 35,665 | |
| | | |
Liabilities | | | |
Accounts payable | 132 | | | 224 | |
Accrued liabilities | 332 | | | 269 | |
Current liabilities - related parties | 387 | | | 343 | |
Accrued property, plant and equipment | 140 | | | 128 | |
| | | |
Long-term debt due within one year | 1 | | | 988 | |
Accrued interest payable | 187 | | | 237 | |
Operating lease liabilities | 48 | | | 46 | |
| | | |
Other current liabilities | 172 | | | 166 | |
Total current liabilities | 1,399 | | | 2,401 | |
Long-term deferred revenue | 295 | | | 219 | |
Long-term liabilities - related parties | 343 | | | 338 | |
Long-term debt | 20,417 | | | 18,808 | |
Deferred income taxes | 12 | | | 13 | |
Long-term operating lease liabilities | 219 | | | 230 | |
Other long-term liabilities | 119 | | | 142 | |
Total liabilities | 22,804 | | | 22,151 | |
Commitments and contingencies (see Note 15) | | | |
Series A preferred units (30 million and 30 million units issued and outstanding) | 970 | | | 968 | |
| | | |
Equity | | | |
Common unitholders - public (354 million and 354 million units issued and outstanding) | 8,533 | | | 8,413 | |
Common unitholders - MPC (647 million and 647 million units issued and outstanding) | 3,581 | | | 3,293 | |
Series B preferred units (0 million and 0.6 million units issued and outstanding) | — | | | 611 | |
Accumulated other comprehensive loss | (4) | | | (8) | |
Total MPLX LP partners’ capital | 12,110 | | | 12,309 | |
Noncontrolling interests | 236 | | | 237 | |
Total equity | 12,346 | | | 12,546 | |
Total liabilities, preferred units and equity | $ | 36,120 | | | $ | 35,665 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Partnership | | | | | | |
(In millions) | Common Unit-holders Public | | Class B Unit-holders Public | | Common Unit-holder MPC | | Common Unit-holder GP | | General Partner MPC | | Accumulated Other Comprehensive Loss | | Non-controlling Interests | | Equity of Predecessor(1) | | Total |
Balance at December 31, 2015 | $ | 7,691 |
| | $ | 266 |
| | $ | 465 |
| | $ | — |
| | $ | 819 |
| | $ | — |
| | $ | 13 |
| | $ | 692 |
| | $ | 9,946 |
|
Distributions to MPC from Predecessor | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (104 | ) | | (104 | ) |
Contribution from MPC | — |
| | — |
| | 84 |
| | — |
| | 141 |
| | — |
| | — |
| | — |
| | 225 |
|
Contribution of MarkWest Hydrocarbon from MPC | — |
| | — |
| | — |
| | — |
| | (188 | ) | | — |
| | — |
| | — |
| | (188 | ) |
Distribution of MarkWest Hydrocarbon to MPC | — |
| | — |
| | — |
| | — |
| | 565 |
| | — |
| | — |
| | — |
| | 565 |
|
Issuance of units under ATM Program | 499 |
| | — |
| | — |
| | — |
| | 11 |
| | — |
| | — |
| | — |
| | 510 |
|
Net (loss) income | (51 | ) | | — |
| | (10 | ) | | — |
| | 136 |
| | — |
| | 3 |
| | 149 |
| | 227 |
|
Allocation of MPC's net investment at acquisition | — |
| | — |
| | 669 |
| | — |
| | (337 | ) | | — |
| | — |
| | (332 | ) | | — |
|
Distributions to unitholders and general partner | (378 | ) | | — |
| | (98 | ) | | — |
| | (136 | ) | | — |
| | — |
| | — |
| | (612 | ) |
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
|
Class B unit conversion | 133 |
| | (133 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-cash contribution from MPC | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 334 |
| | 334 |
|
Equity-based compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Deferred income tax impact from changes in equity | (2 | ) | | — |
| | (13 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| | (17 | ) |
Balance at September 30, 2016 | $ | 7,898 |
| | $ | 133 |
| | $ | 1,097 |
|
| $ | — |
| | $ | 1,009 |
|
| $ | — |
| | $ | 17 |
| | $ | 739 |
| | $ | 10,893 |
|
| | | | | | | | | | | | | | | | |
|
|
Balance at December 31, 2016 | $ | 8,086 |
| | $ | 133 |
| | $ | 1,069 |
| | $ | — |
| | $ | 1,013 |
| | $ | — |
| | $ | 18 |
| | $ | 791 |
| | $ | 11,110 |
|
Distributions to MPC from Predecessor | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (113 | ) | | (113 | ) |
Distributions of cash received from Joint-Interest Acquisition entities to MPC | — |
| | — |
| | — |
| | — |
| | (13 | ) | | — |
| | — |
| | — |
| | (13 | ) |
Issuance of units under ATM Program | 473 |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | 483 |
|
Net income | 212 |
| | — |
| | 68 |
| | 5 |
| | 222 |
| | — |
| | 3 |
| | 36 |
| | 546 |
|
Contribution from MPC | — |
| | — |
| | — |
| | — |
| | — |
| | (14 | ) | | — |
| | 689 |
| | 675 |
|
Allocation of MPC's net investment at acquisition | — |
| | — |
| | 845 |
| | 824 |
| | (266 | ) | | — |
| | — |
| | (1,403 | ) | | — |
|
Distribution to MPC for acquisitions | — |
| | — |
| | (537 | ) | | — |
| | (1,394 | ) | | — |
| | — |
| | — |
| | (1,931 | ) |
Distributions to unitholders and general partner | (452 | ) | | — |
| | (143 | ) | | (7 | ) | | (198 | ) | | — |
| | — |
| | — |
| | (800 | ) |
Distributions to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | (4 | ) |
Contributions from noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 128 |
| | — |
| | 128 |
|
Class B unit conversion | 133 |
| | (133 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Equity-based compensation | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
|
Balance at September 30, 2017 | $ | 8,457 |
| | $ | — |
| | $ | 1,302 |
|
| $ | 822 |
| | $ | (626 | ) | | $ | (14 | ) | | $ | 145 |
| | $ | — |
| | $ | 10,086 |
|
| |
(1) | Financial information has been retrospectively adjusted for the acquisition of HST, WHC and MPLXT from MPC. See Notes 1 and 3. |
The accompanying notes are an integral part of these consolidated financial statements.
MPLX LP
Consolidated Statements of Cash Flows (Unaudited) | | | | | | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 |
Operating activities: | | | |
Net income | $ | 2,822 | | | $ | 3,154 | |
Adjustments to reconcile net income to net cash provided by operating activities: | | | |
Amortization of deferred financing costs | 42 | | | 55 | |
Depreciation and amortization | 907 | | | 925 | |
| | | |
Deferred income taxes | (1) | | | 4 | |
| | | |
Gain on sales-type leases | — | | | (509) | |
(Gain)/loss on disposal of assets | (15) | | | 23 | |
Income from equity method investments | (438) | | | (335) | |
Distributions from unconsolidated affiliates | 526 | | | 405 | |
Change in fair value of derivatives | (3) | | | (62) | |
Changes in: | | | |
Receivables | (31) | | | (219) | |
Inventories | (15) | | | (7) | |
Accounts payable and accrued liabilities | (56) | | | 49 | |
Assets/liabilities - related parties | 89 | | | 52 | |
| | | |
Right of use assets/operating lease liabilities | 4 | | | 1 | |
Deferred revenue | 65 | | | 64 | |
All other, net | 12 | | | 51 | |
Net cash provided by operating activities | 3,908 | | | 3,651 | |
Investing activities: | | | |
Additions to property, plant and equipment | (662) | | | (535) | |
Acquisitions, net of cash acquired | — | | | (28) | |
Disposal of assets | 25 | | | 74 | |
| | | |
Investments in unconsolidated affiliates | (90) | | | (198) | |
| | | |
Distributions from unconsolidated affiliates - return of capital | — | | | 11 | |
| | | |
Net cash used in investing activities | (727) | | | (676) | |
Financing activities: | | | |
Long-term debt borrowings | 1,589 | | | 3,379 | |
Long-term debt repayments | (1,001) | | | (2,202) | |
Related party debt borrowings | — | | | 2,824 | |
Related party debt repayments | — | | | (4,274) | |
Debt issuance costs | (15) | | | (29) | |
| | | |
Unit repurchases | — | | | (315) | |
Redemption of Series B preferred units | (600) | | | — | |
| | | |
| | | |
| | | |
| | | |
Distributions to noncontrolling interests | (30) | | | (29) | |
Distributions to Series A preferred unitholders | (69) | | | (63) | |
Distributions to Series B preferred unitholders | (21) | | | (41) | |
Distributions to unitholders and general partner | (2,329) | | | (2,144) | |
| | | |
Contributions from MPC | 20 | | | 30 | |
| | | |
All other, net | (3) | | | (3) | |
Net cash used in financing activities | (2,459) | | | (2,867) | |
Net change in cash, cash equivalents and restricted cash | 722 | | | 108 | |
Cash, cash equivalents and restricted cash at beginning of period | 238 | | | 13 | |
Cash, cash equivalents and restricted cash at end of period | $ | 960 | | | $ | 121 | |
| | | |
| | | |
| | | |
The accompanying notes are an integral part of these consolidated financial statements.
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 | $ | 8,413 | | | $ | 3,293 | | | $ | 611 | | | $ | (8) | | | $ | 237 | | | | | $ | 12,546 | | | | $ | 968 | |
Net income | 323 | | | 592 | | | 5 | | | — | | | 9 | | | | | 929 | | | | 23 | |
| | | | | | | | | | | | | | | | |
Redemption of Series B preferred units | (2) | | | (3) | | | (595) | | | — | | | — | | | | | (600) | | | | — | |
Distributions | (275) | | | (502) | | | (21) | | | — | | | (10) | | | | | (808) | | | | (23) | |
Contributions | — | | | 8 | | | — | | | — | | | — | | | | | 8 | | | | — | |
Other | — | | | — | | | — | | | 4 | | | 1 | | | | | 5 | | | | — | |
Balance at March 31, 2023 | $ | 8,459 | | | $ | 3,388 | | | $ | — | | | $ | (4) | | | $ | 237 | | | | | $ | 12,080 | | | | $ | 968 | |
Net income | 322 | | | 588 | | | — | | | — | | | 9 | | | | | 919 | | | | 23 | |
| | | | | | | | | | | | | | | | |
Distributions | (274) | | | (502) | | | — | | | — | | | (9) | | | | | (785) | | | | (23) | |
Contributions | — | | | 5 | | | — | | | — | | | — | | | | | 5 | | | | — | |
Other | 1 | | | 1 | | | — | | | — | | | — | | | | | 2 | | | | — | |
Balance at June 30, 2023 | $ | 8,508 | | | $ | 3,480 | | | $ | — | | | $ | (4) | | | $ | 237 | | | | | $ | 12,221 | | | | $ | 968 | |
Net income | 297 | | | 596 | | | — | | | — | | | 10 | | | | | 903 | | | | 25 | |
Unit repurchases | — | | | — | | | — | | | — | | | — | | | | | — | | | | — | |
Distributions | (274) | | | (502) | | | — | | | — | | | (11) | | | | | (787) | | | | (23) | |
Contributions | — | | | 7 | | | — | | | — | | | — | | | | | 7 | | | | — | |
Other | 2 | | | — | | | — | | | — | | | — | | | | | 2 | | | | — | |
Balance at September 30, 2023 | $ | 8,533 | | | $ | 3,581 | | | $ | — | | | $ | (4) | | | $ | 236 | | | | | $ | 12,346 | | | | $ | 970 | |
| | | | | | | | | | | | | | | | |
| Partnership | | | | | | | | | | | |
| 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, 2021 | $ | 8,579 | | | $ | 2,638 | | | $ | 611 | | | $ | (17) | | | $ | 241 | | | | | $ | 12,052 | | | | $ | 965 | |
Net income | 287 | | | 506 | | | 11 | | | — | | | 8 | | | | | 812 | | | | 21 | |
Unit repurchases | (100) | | | — | | | — | | | — | | | — | | | | | (100) | | | | — | |
Distributions | (260) | | | (456) | | | (21) | | | — | | | (9) | | | | | (746) | | | | (21) | |
Contributions | — | | | 10 | | | — | | | — | | | — | | | | | 10 | | | | — | |
Other | (1) | | | — | | | — | | | 9 | | | — | | | | | 8 | | | | — | |
Balance at March 31, 2022 | $ | 8,505 | | | $ | 2,698 | | | $ | 601 | | | $ | (8) | | | $ | 240 | | | | | $ | 12,036 | | | | $ | 965 | |
Net income | 304 | | | 540 | | | 10 | | | — | | | 9 | | | | | 863 | | | | 21 | |
Unit repurchases | (35) | | | — | | | — | | | — | | | — | | | | | (35) | | | | — | |
Distributions | (257) | | | (457) | | | — | | | — | | | (10) | | | | | (724) | | | | (21) | |
Contributions | — | | | 2 | | | — | | | — | | | — | | | | | 2 | | | | — | |
Other | 1 | | | 1 | | | — | | | — | | | — | | | | | 2 | | | | — | |
Balance at June 30, 2022 | $ | 8,518 | | | $ | 2,784 | | | $ | 611 | | | $ | (8) | | | $ | 239 | | | | | $ | 12,144 | | | | $ | 965 | |
Net income | 502 | | | 893 | | | 10 | | | — | | | 9 | | | | | 1,414 | | | | 23 | |
Unit repurchases | (196) | | | — | | | — | | | — | | | — | | | | | (196) | | | | — | |
Distributions | (258) | | | (456) | | | (20) | | | — | | | (10) | | | | | (744) | | | | (21) | |
Contributions | — | | | 55 | | | — | | | — | | | — | | | | | 55 | | | | — | |
Other | 3 | | | — | | | — | | | — | | | — | | | | | 3 | | | | — | |
Balance at September 30, 2022 | $ | 8,569 | | | $ | 3,276 | | | $ | 601 | | | $ | (8) | | | $ | 238 | | | | | $ | 12,676 | | | | $ | 967 | |
The accompanying notes are an integral part of these consolidated financial statements.
Notes to Consolidated Financial Statements (Unaudited)
1. Description of the Business and Basis of Presentation
Description of the Business –
MPLX LP is a diversified, growth-orientedlarge-cap master limited partnership formed by Marathon Petroleum Corporation. MPLX LPCorporation that owns and its subsidiaries (collectively, the “Partnership”)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 gathering, transportation, fractionation, storage and marketing of NGLs;NGLs. MPLX’s principal executive office is located in Findlay, Ohio. MPLX was formed on March 27, 2012 as a Delaware limited partnership and the transportation, storage and distribution of crude oil and refined petroleum products, principally for our sponsor. References to “MPC” refer collectively to Marathon Petroleum Corporation andcompleted its subsidiaries, other than the Partnership.initial public offering on October 31, 2012.
The Partnership’sMPLX’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”), which is focused onrelates primarily to crude oil, refined products, other hydrocarbon-based products and refined petroleum productsrenewables; and Gathering and Processing (“G&P”), which is focused onrelates primarily to natural gas and NGLs. See Note 9 for additional information regarding operations.
Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties have been recorded as Noncontrolling interests in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method.
Effective March 1, 2017, the Partnership acquired pipeline, storage and terminal businesses that are operated through Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) (collectively with Hardin Street Marine LLC (“HSM”), “Predecessor”) from MPC. The acquisition from MPC was considered a transfer between entities under common control. Accordingly, the Partnership recorded the acquisition from MPC on its Consolidated Balance Sheets at MPC’s historical basis instead of fair value. Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted to furnish comparative information since inception of common control. Therefore, the accompanying consolidated financial statements and related notes of MPLX LP have been retrospectively adjusted to include the historical results of the businesses acquired from MPC prior to the effective dates of the acquisition. See Note 37 for additional information regarding the HST, WHCoperations and MPLXT acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equitythese segments.
Basis of Predecessor on a historical basis. The financial statements of Predecessor have been prepared from the separate records maintained by MPC and may not necessarily be indicative of the conditions or the results of operations that would have existed if Predecessor had been operated as an unaffiliated entity.Presentation
In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued until declared. However, when distributions related to the IDRs are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the limited partner unitholders based on their respective ownership percentages. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 6.
The accompanyingThese interim consolidated financial statements are unaudited; however, in the opinion of the Partnership’sMPLX’s management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules and regulations of the SEC applicable to interim period financial statements and do not include all of the information and disclosures required by GAAP for complete financial statements. Certain information derived from our audited annual financial statements, prepared in accordance with GAAP, has been condensed or omitted from these interim financial statements.
These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in theour Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.2022. The results of operations for the three and nine months ended September 30, 20172023 are not necessarily indicative of the results to be expected for the full year.
MPLX’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly owned consolidated subsidiaries, the interests owned by third parties have been recorded as Noncontrolling interests on the accompanying Consolidated Balance Sheets. Intercompany accounts and transactions have been eliminated. MPLX’s investments in which MPLX exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. MPLX’s investments in VIEs in which MPLX exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method.
2. Accounting Standards
RecentlyNot Yet Adopted
ASU 2023-01, Leases (Topic 842): Common Control Arrangements
In October 2016,March 2023, the FASB issued an accounting standards updateASU to amend the consolidation guidance issued in February 2015certain provisions of ASC 842 that apply to require that a decision maker consider, in the determination of the primary beneficiary, its indirect interest in a VIE held by aarrangements between related party that isparties under common control on a proportionate basis only.control. The change was effective for the financial statements for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The Partnership was required to apply the standard retrospectively to January 1, 2016, the date on which the Partnership adopted the consolidation guidance issued in February 2015. The Partnership adopted this accounting standards update in the first quarter of 2017 and it did not have an impact on the consolidated financial statements.
In March 2016, the FASB issued an accounting standards update onASU amends the accounting for employee share-based payments. This updatethe amortization period of leasehold improvements in common-control leases for all entities and requires certain disclosures when the recognition of income tax effects of awards throughlease term is shorter than the income statement when awards vest or are settled. It also increases the amount an employer can withhold for tax purposes without triggering liability accounting. Lastly, it allows employers to make a policy election to account for forfeitures as they occur. The changes were effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Under the new guidance, the Partnership will continue estimating forfeiture rates to calculate compensation cost. The Partnership adopted this accounting standards update in the first quarter of 2017 and it did not have a material impact on the consolidated financial statements.
Not Yet Adopted
In August 2017, the FASB issued an accounting standards update to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, as well as eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019 with early adoption permitted. The Partnership is in the process of determining the impact of this guidance, including transition elections and required disclosures, on the consolidated financial statements and the timing of adoption.
In May 2017, the FASB issued an accounting standards update to provide guidance about when changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity should account for the effects of a modification unless the fair value, vesting conditions and balance sheet classificationuseful life of the modified award is the same as the original award immediately before the original award is modified. The Partnership will adopt the new standard on a prospective basis beginning on January 1, 2018. The application of this new accounting standard is not expected to have a material impact on the consolidated financial statements.
In February 2017, the FASB issued an accounting standards update addressing the derecognition of nonfinancial assets. The guidance defines in-substance nonfinancial assets, and states that the derecognition of business activities should be evaluated under the consolidation guidance, with limited exceptions related to conveyances of oil and gas mineral rights or contracts with customers. The standard eliminates the previous exclusion for businesses that are in-substance real estate, and eliminates some differences based on whether a transferred set is that of assets or a business and whether the transfer is to a joint venture. The standard must be implemented in conjunction with the implementation of the revenue recognition accounting standards update, which the Partnership will implement January 1, 2018. The Partnership plans to adopt the new standard using the modified retrospective method and does not expect the application of this accounting standards update to have a material impact on the consolidated financial statements.
In January 2017, the FASB issued an accounting standards update which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, the recognition of an impairment charge is calculated based on the amount by which the carrying amount exceeds the reporting unit’s fair value, which could be different from the amount calculated under the current method using the implied fair value of the goodwill; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The guidance should be applied on a prospective basis, and is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership is in the process of determining the impact of the accounting standards update on the consolidated financial statements.
In January 2017, the FASB issued an accounting standards update to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of
assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The changeasset. This ASU is effective for fiscal years beginning after December 15, 2017, and2023, including interim periods within those fiscal years. The guidance will be applied prospectively and earlyEarly adoption is permitted for certain transactions. The Partnership is inpermitted. We do not expect the process of evaluating this accounting standards update and determining whether it will early adopt.
In November 2016, the FASB issued an accounting standards update requiring that the statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective application is required. The application of this accounting standards update will not have a material impact on the Consolidated Statements of Cash Flows.
In August 2016, the FASB issued an accounting standards update related to the classification of certain cash flows. The accounting standards update provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective application is required. The Partnership does not expect application of this accounting standards updateASU to have a material impact on the Consolidated Statements of Cash Flows.
In June 2016, the FASB issued an accounting standards update related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses are based on an expected loss approach which includes estimates of losses over the life of exposure that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership does not expect application of this accounting standards update to have a material impact on the consolidated financial statements.
In February 2016, the FASB issued an accounting standards update requiring lessees to record virtually all leases on their balance sheets. The accounting standards update also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The change will be effective on a modified retrospective basis for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. The Partnership is currently evaluating the impact of this standard on the Partnership’s financial statements and disclosures, internal controls and accounting policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path to implementation. The Partnership does not plan to early adopt the standard. The Partnership believes the impact will be material on theour consolidated financial statements as all operating leases will be recognized as a right of use asset and lease obligation. Based on results of the evaluation process to date, the Partnership also believes the impact on existing processes, controls and information systems may be material.or financial disclosures.
In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The update also requires the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes and the separate presentation of financial assets and liabilities by measurement category and form on the balance sheet and accompanying notes. The update eliminates the requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments measured at amortized cost. Lastly, the accounting standards update requires separate presentation in other comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair value option for financial instruments. The changes are effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017. Early adoption is permitted only for guidance regarding presentation of the liability’s credit risk. The Partnership does not expect application of this accounting standards update to have a material impact on the consolidated financial statements.
In May 2014, the FASB issued Accounting Standards Update 2014-09 which created Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (“ASC 606”). The guidance in ASC 606 states that revenue is recognized when a customer obtains controlTable of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The change will be effective on a retrospective or modified retrospective basis for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted no earlier than January 1, 2017.Contents
The Partnership will adopt the revenue recognition standard during the first quarter of 2018. The Partnership plans to adopt the new standard using the modified retrospective method, which will result in a cumulative effect adjustment as of the date of adoption. By selecting this adoption method, the Partnership will disclose the amount by which each financial statement line item is affected by the standard in the current reporting period after adoption as compared with the guidance that was in effect before adoption.
The Partnership is currently evaluating the impact of the revenue recognition standard on its consolidated financial statements and disclosures, internal controls and accounting policies. This evaluation process includes a phased approach, the first phase of which includes reviewing a sample of contracts and transaction types across segments. This phase was completed as of September 30, 2017.
Based on the results of the first phase assessment, the Partnership has reached conclusions for all material contract types. Revenue recognition patterns will not change for fee-based or percent-of-proceeds contracts. The Partnership does expect certain amounts to be grossed up in revenue and cost of revenues as a result of implementation, specifically related to third-party reimbursements from customers and commodities received as consideration in service agreements, such as keep-whole arrangements. In the third quarter of 2017, the Partnership finalized a conclusion on the valuation of non-cash consideration received in the form of a commodity product, with the valuation being performed on the date the service performance obligation is completed.
The Partnership is in the process of finalizing the second phase of implementation, which includes the calculation of the impact of the new standard on results and the development of new policies, procedures and disclosures related to the application upon adoption. The Partnership believes third-party reimbursements included in the transaction price would have resulted in a gross up in 2016 and 2017 service revenue and cost of revenues between $300 million and $350 million annually, with no impact to net income. The Partnership will provide a summary of the total ASC 606 impact in the Annual Report on Form 10-K for the year ended December 31, 2017.
3. AcquisitionsInvestments and Noncontrolling Interests
Joint-Interest Acquisition
On September 1, 2017, the Partnership entered into a Membership Interests and Shares Contributions Agreement (the “September 2017 Contributions Agreement”) with MPLX GP LLC (“MPLX GP”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, whereby the Partnership agreed to acquire certain ownership interests in joint venture entities indirectly held by MPC. Pursuant to the September 2017 Contributions Agreement, MPC Investment agreed to contribute: all of the membership interests of Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”); all of the membership interests of MPL Louisiana Holdings LLC, which holds a 40.7 percent interest in LOOP LLC (“LOOP”); a 58.52 percent interest in LOCAP LLC (“LOCAP”); and a 24.51 percent interest in Explorer Pipeline Company (“Explorer”), through a series of intercompany contributions to the Partnership for an agreed upon purchase price of approximately $420 million in cash and equity consideration valued at approximately $630 million for total consideration of $1.05 billion (collectively, the “Joint-Interest Acquisition”). The number of common units representing the equity consideration was then determined by dividing the contribution amount by the simple average of the ten day trading volume weighted average NYSE price of a common unit for the ten trading days ending at market close on August 31, 2017. The fair value of the common and general partner units issued was approximately $653 million based on the closing common unit price as of September 1, 2017, as recorded on the Consolidated Statements of Equity, for a total purchase price of $1.07 billion. The equity issued consisted of: (i) 13,719,017 common units to MPLX GP, (ii) 3,350,893 common units to MPLX Logistics and (iii) 1,441,224 common units to MPLX Holdings. The Partnership also issued 377,778 general partner units to MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in the Partnership.
Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension (“SAX”) crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations. LOOP owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana, pipelines and onshore storage facilities. LOOP also manages the operations of LOCAP, an affiliate pipeline system. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the mid-continent region of the United States. Explorer owns and operates an approximate 1,830-mile common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining complex to the Midwest United States. The Partnership accounts for the Joint-Interest Acquisition entities as equity method investments within its L&S segment.
As a transfer between entities under common control, the Partnership recorded the Joint-Interest Acquisition on its Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss. The Partnership recognizes an accumulated other comprehensive loss on its Consolidated Balance Sheets relating to pension and other post-retirement benefits provided by the LOOP and Explorer joint-interests to their employees. MPLX LP is not a sponsor of these benefit plans. There were no changes to Accumulated other comprehensive loss during the period September 1, 2017 through September 30, 2017.
Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to periods prior to the acquisition will be prorated on a daily basis with MPLX LP retaining the portion of distributions beginning on the closing date. All amounts distributed to MPLX LP related to periods before the acquisition will be paid to MPC. Additionally, MPLX LP has agreed to pay MPC for any distributions of cash from LOOP related to the sale of LOOP’s excess crude oil inventory. Because the future distributions or payments cannot be reasonably quantified, a liability was not recorded in connection with the acquisition. MPLX LP subsequently received distributions related to the third quarter 2017 and recorded a liability to MPC and a corresponding decrease to the general partner’s equity for $13 million, as shown on the Consolidated Statements of Equity.
There is no income associated with the Joint-Interest Acquisition included in the Consolidated Statements of Income since the September 1, 2017 acquisition date, as the Partnership accounts for these investments in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 related to the acquired interests is approximately $645 million and reported under the caption Equity method investments on the Consolidated Balance Sheets. MPC agreed to waive approximately two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive approximately two-thirds of the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.
Acquisition of Hardin Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC
MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Pursuant to a Membership Interests Contributions Agreement entered into on March 1, 2017 by the Partnership with MPLX GP, MPLX Logistics, MPLX Holdings and MPC Investment, each a wholly-owned subsidiary of MPC, MPC Investment agreed to contribute the outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average NYSE price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million, as recorded on the Consolidated Statements of Equity, and consisted of (i) 9,197,900 common units to MPLX GP, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to MPLX GP in order to maintain its two percent GP Interest in the Partnership. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the common units issued in connection with the Transaction. As a result of this waiver, MPC did not receive two-thirds of the general partner distributions or IDRs that would have otherwise accrued on such common units with respect to the first quarter 2017 distributions. The value of these waived distributions was $6 million.
HST owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. As of the acquisition date, these pipeline systems consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines. WHC owns and operates nine butane and propane storage caverns located in Michigan with approximately 1.8 million barrels of NGL storage capacity. As of the acquisition date, MPLXT owned and operated 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products. Additionally, MPLXT operated one leased terminal and had partial ownership interest in two terminals. Collectively, these 62 terminals have a combined shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States. The Partnership accounts for these businesses within its L&S segment.
The Partnership retrospectively adjusted the historical financial results for all periods to give effect to the acquisition of HST and WHC effective January 1, 2015, and the acquisition of MPLXT effective April 1, 2016, as required for transactions between entities under common control. Prior to these dates, these entities were not considered businesses and, therefore, there are no financial results from which to recast.
The following tables present the Partnership’s previously reported unaudited Consolidated Statements of Income for the three and nine months ended September 30, 2016, retrospectively adjusted for the acquisition of HST, WHC and MPLXT:
|
| | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2016 |
(In millions, except per unit data) | MPLX LP (Previously Reported) | | HST/WHC | | MPLXT | | Eliminations(1) | | MPLX LP (Currently Reported) |
Revenues and other income: | | | | | | | | | |
Service revenue | $ | 250 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 250 |
|
Service revenue - related parties | 153 |
| | 28 |
| | 72 |
| | — |
| | 253 |
|
Rental income | 77 |
| | — |
| | — |
| | — |
| | 77 |
|
Rental income - related parties | 29 |
| | 13 |
| | 26 |
| | — |
| | 68 |
|
Product sales | 157 |
| | — |
| | — |
| | — |
| | 157 |
|
Product sales - related parties | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Income from equity method investments | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
Gain on sale of assets | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Other income | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Other income - related parties | 26 |
| | — |
| | — |
| | (4 | ) | | 22 |
|
Total revenues and other income | 703 |
| | 41 |
| | 98 |
| | (4 | ) | | 838 |
|
Costs and expenses: | | | | | | | | | |
Cost of revenues (excludes items below) | 90 |
| | 10 |
| | 22 |
| | — |
| | 122 |
|
Purchased product costs | 117 |
| | — |
| | — |
| | — |
| | 117 |
|
Rental cost of sales | 11 |
| | 2 |
| | — |
| | — |
| | 13 |
|
Rental cost of sales - related parties | — |
| | 1 |
| | — |
| | (1 | ) | | — |
|
Purchases - related parties | 84 |
| | 4 |
| | 24 |
| | (3 | ) | | 109 |
|
Depreciation and amortization | 138 |
| | 4 |
| | 9 |
| | — |
| | 151 |
|
General and administrative expenses | 46 |
| | 2 |
| | 8 |
| | — |
| | 56 |
|
Other taxes | 10 |
| | — |
| | 2 |
| | — |
| | 12 |
|
Total costs and expenses | 496 |
| | 23 |
| | 65 |
| | (4 | ) | | 580 |
|
Income from operations | 207 |
| | 18 |
| | 33 |
| | — |
| | 258 |
|
Interest expense (net of amounts capitalized) | 51 |
| | — |
| | — |
| | — |
| | 51 |
|
Other financial costs | 13 |
| | — |
| | — |
| | — |
| | 13 |
|
Income before income taxes | 143 |
| | 18 |
| | 33 |
| | — |
| | 194 |
|
Net income | 143 |
| | 18 |
| | 33 |
| | — |
| | 194 |
|
Less: Net income attributable to noncontrolling interests | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Less: Net income attributable to Predecessor | — |
| | 18 |
| | 33 |
| | — |
| | 51 |
|
Net income attributable to MPLX LP | 141 |
| | — |
| | — |
| | — |
| | 141 |
|
Less: Preferred unit distributions | 16 |
| | — |
| | — |
| | — |
| | 16 |
|
Less: General partner’s interest in net income attributable to MPLX LP | 51 |
| | — |
| | — |
| | — |
| | 51 |
|
Limited partners’ interest in net income attributable to MPLX LP | $ | 74 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 74 |
|
| |
(1) | Represents intercompany transactions eliminated during the consolidation process, in accordance with GAAP. |
|
| | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(In millions, except per unit data) | MPLX LP (Previously Reported) | | HST/WHC | | MPLXT | | Eliminations(1) | | MPLX LP (Currently Reported) |
Revenues and other income: | | | | | | | | | |
Service revenue | $ | 712 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 712 |
|
Service revenue - related parties | 448 |
| | 82 |
| | 146 |
| | — |
| | 676 |
|
Rental income | 218 |
| | — |
| | — |
| | — |
| | 218 |
|
Rental income - related parties | 84 |
| | 36 |
| | 52 |
| | — |
| | 172 |
|
Product sales | 394 |
| | — |
| | — |
| | — |
| | 394 |
|
Product sales - related parties | 8 |
| | — |
| | — |
| | — |
| | 8 |
|
Loss from equity method investments | (72 | ) | | — |
| | — |
| | — |
| | (72 | ) |
Gain on sale of assets | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Other income | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
Other income - related parties | 78 |
| | — |
| | — |
| | (11 | ) | | 67 |
|
Total revenues and other income | 1,876 |
| | 118 |
| | 198 |
| | (11 | ) | | 2,181 |
|
Costs and expenses: | | | | | | | | | |
Cost of revenues (excludes items below) | 263 |
| | 24 |
| | 42 |
| | — |
| | 329 |
|
Purchased product costs | 310 |
| | — |
| | — |
| | — |
| | 310 |
|
Rental cost of sales | 39 |
| | 3 |
| | — |
| | — |
| | 42 |
|
Rental cost of sales - related parties | — |
| | 2 |
| | — |
| | (1 | ) | | 1 |
|
Purchases - related parties | 238 |
| | 13 |
| | 45 |
| | (10 | ) | | 286 |
|
Depreciation and amortization | 407 |
| | 12 |
| | 19 |
| | — |
| | 438 |
|
Impairment expense | 130 |
| | — |
| | — |
| | — |
| | 130 |
|
General and administrative expenses | 147 |
| | 5 |
| | 20 |
| | — |
| | 172 |
|
Other taxes | 32 |
| | 2 |
| | 3 |
| | — |
| | 37 |
|
Total costs and expenses | 1,566 |
| | 61 |
| | 129 |
| | (11 | ) | | 1,745 |
|
Income from operations | 310 |
| | 57 |
| | 69 |
| | — |
| | 436 |
|
Related party interest and other financial income | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Interest expense (net of amounts capitalized) | 158 |
| | — |
| | — |
| | — |
| | 158 |
|
Other financial costs | 37 |
| | — |
| | — |
| | — |
| | 37 |
|
Income before income taxes | 114 |
| | 57 |
| | 69 |
| | — |
| | 240 |
|
Benefit for income taxes | (12 | ) | | — |
| | — |
| | — |
| | (12 | ) |
Net income | 126 |
| | 57 |
| | 69 |
| | — |
| | 252 |
|
Less: Net income attributable to noncontrolling interests | 3 |
| | — |
| | — |
| | — |
| | 3 |
|
Less: Net income attributable to Predecessor | 23 |
| | 57 |
| | 69 |
| | — |
| | 149 |
|
Net income attributable to MPLX LP | 100 |
| | — |
| | — |
| | — |
| | 100 |
|
Less: Preferred unit distributions | 25 |
| | — |
| | — |
| | — |
| | 25 |
|
Less: General partner’s interest in net income attributable to MPLX LP | 136 |
| | — |
| | — |
| | — |
| | 136 |
|
Limited partners’ interest in net loss attributable to MPLX LP | $ | (61 | ) |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | (61 | ) |
| |
(1) | Represents intercompany transactions eliminated during the consolidation process, in accordance with GAAP. |
The following table presents the Partnership’s previously reported unaudited Consolidated Statements of Cash Flows, retrospectively adjusted for the acquisition of HST, WHC and MPLXT: |
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(In millions) | MPLX LP (Previously Reported) | | HST/WHC | | MPLXT | | MPLX LP (Currently Reported) |
Increase (decrease) in cash and cash equivalents | | | | | | | |
Operating activities: | | | | | | | |
Net income | $ | 126 |
| | $ | 57 |
| | $ | 69 |
| | $ | 252 |
|
Adjustments to reconcile net income to net cash provided by (used in) operating activities: | | | | |
| | |
Amortization of deferred financing costs | 34 |
| | — |
| | — |
| | 34 |
|
Depreciation and amortization | 407 |
| | 12 |
| | 19 |
| | 438 |
|
Impairment expense | 130 |
| | — |
| | — |
| | 130 |
|
Deferred income taxes | (16 | ) | | — |
| | — |
| | (16 | ) |
Asset retirement expenditures | (3 | ) | | (1 | ) | | — |
| | (4 | ) |
Gain on disposal of assets | (1 | ) | | — |
| | — |
| | (1 | ) |
Loss from equity method investments | 72 |
| | — |
| | — |
| | 72 |
|
Distributions from unconsolidated affiliates | 111 |
| | — |
| | — |
| | 111 |
|
Changes in: | | | | | | | |
Current receivables | (44 | ) | | 1 |
| | — |
| | (43 | ) |
Inventories | (4 | ) | | — |
| | — |
| | (4 | ) |
Fair value of derivatives | 28 |
| | — |
| | — |
| | 28 |
|
Current accounts payable and accrued liabilities | 59 |
| | (1 | ) | | 6 |
| | 64 |
|
Receivables from / liabilities to related parties | 15 |
| | 3 |
| | (122 | ) | | (104 | ) |
All other, net | 18 |
| | 2 |
| | (2 | ) | | 18 |
|
Net cash provided by (used in) operating activities | 932 |
| | 73 |
| | (30 | ) | | 975 |
|
Investing activities: | | | | | | | |
Additions to property, plant and equipment | (874 | ) | | (36 | ) | | (33 | ) | | (943 | ) |
Investments - net related party loans | 77 |
| | (37 | ) | | 63 |
| | 103 |
|
Investments in unconsolidated affiliates | (56 | ) | | — |
| | — |
| | (56 | ) |
All other, net | 4 |
| | — |
| | — |
| | 4 |
|
Net cash (used in) provided by investing activities | (849 | ) | | (73 | ) | | 30 |
| | (892 | ) |
Financing activities: | | | | | | | |
Long-term debt - borrowings | 434 |
| | — |
| | — |
| | 434 |
|
- repayments | (1,312 | ) | | — |
| | — |
| | (1,312 | ) |
Related party debt - borrowings | 2,215 |
| | — |
| | — |
| | 2,215 |
|
- repayments | (2,223 | ) | | — |
| | — |
| | (2,223 | ) |
Net proceeds from equity offerings | 510 |
| | — |
| | — |
| | 510 |
|
Issuance of redeemable preferred units | 984 |
| | — |
| | — |
| | 984 |
|
Distributions to preferred unitholders | (9 | ) | | — |
| | — |
| | (9 | ) |
Distributions to unitholders and general partner | (612 | ) | | — |
| | — |
| | (612 | ) |
Distributions to noncontrolling interests | (3 | ) | | — |
| | — |
| | (3 | ) |
Contributions from noncontrolling interests | 4 |
| | — |
| | — |
| | 4 |
|
Consideration payment to Class B unitholders | (25 | ) | | — |
| | — |
| | (25 | ) |
All other, net | (2 | ) | | — |
| | — |
| | (2 | ) |
Contribution from MPC | 225 |
| | — |
| | — |
| | 225 |
|
Distributions to MPC from Predecessor | (104 | ) | | — |
| | — |
| | (104 | ) |
Net cash provided by financing activities | 82 |
| | — |
| | — |
| | 82 |
|
Net increase in cash and cash equivalents | 165 |
| | — |
| | — |
| | 165 |
|
Cash and cash equivalents at beginning of period | 43 |
| | — |
| | — |
| | 43 |
|
Cash and cash equivalents at end of period | $ | 208 |
| | $ | — |
| | $ | — |
| | $ | 208 |
|
Acquisition of Ozark Pipeline
On March 1, 2017, the Partnership acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for approximately $219 million, including purchase price adjustments made in the second quarter of 2017. Based on the final fair value estimates of assets acquired and liabilities assumedMPLX’s equity method investments at the acquisition date, the purchase price was primarily allocated to property, plant and equipment.dates indicated:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Ownership as of | | Carrying value at |
| | | September 30, | | September 30, | | December 31, |
(In millions, except ownership percentages) | VIE | | 2023 | | 2023 | | 2022 |
L&S | | | | | | | |
Andeavor Logistics Rio Pipeline LLC | X | | 67% | | $ | 174 | | | $ | 177 | |
Illinois Extension Pipeline Company, L.L.C. | | | 35% | | 238 | | | 236 | |
LOOP LLC | | | 41% | | 301 | | | 287 | |
MarEn Bakken Company LLC(1) | | | 25% | | 453 | | | 475 | |
Minnesota Pipe Line Company, LLC | | | 17% | | 174 | | | 178 | |
Whistler Pipeline LLC | | | 38% | | 212 | | | 211 | |
Other(2) | X | | | | 298 | | | 269 | |
Total L&S | | | | | 1,850 | | | 1,833 | |
G&P | | | | | | | |
Centrahoma Processing LLC | | | 40% | | 117 | | | 131 | |
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C | X | | 67% | | 339 | | | 335 | |
MarkWest Torñado GP, L.L.C. | X | | 60% | | 310 | | | 306 | |
MarkWest Utica EMG, L.L.C. | X | | 58% | | 684 | | | 669 | |
Rendezvous Gas Services, L.L.C. | X | | 78% | | 130 | | | 137 | |
Sherwood Midstream Holdings LLC | X | | 51% | | 116 | | | 125 | |
Sherwood Midstream LLC | X | | 50% | | 507 | | | 512 | |
Other(2) | X | | | | 46 | | | 47 | |
Total G&P | | | | | 2,249 | | | 2,262 | |
Total | | | | | $ | 4,099 | | | $ | 4,095 | |
(1) The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originatinginvestment in Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting approximately 230 mbpd. The Partnership accounts for the Ozark pipeline within its L&S segment.
The amounts of revenue and income from operations associated with the acquisition included in the Consolidated Statements of Income, since the March 1, 2017 acquisition date, are as follows: |
| | | | | | | |
(In millions) | Three Months Ended September 30, 2017 | | Seven Months Ended September 30, 2017 |
Revenues and other income | $ | 19 |
| | $ | 45 |
|
Income from operations | 6 |
| | 17 |
|
Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2016, the consolidated pro forma results would not have been materially different from reported results.
MarEn Bakken
On February 15, 2017, the Partnership closed on a joint venture, MarEn Bakken Company LLC (“MarEn Bakken”), with Enbridge Energy Partners L.P. in which MPLX LP acquired a partial,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 Company Pipeline projects, collectively referred to as the Bakken Pipeline system from Energy Transfer Partners, L.P. and Sunoco Logistics Partners, L.P. The Partnership contributed $500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a 36.75 percent indirect interest in the Bakken Pipeline system. The Partnership holds, through a subsidiary, a 25 percent interest in MarEn Bakken, which equates to a 9.1875 percent indirect interest in the Bakken Pipeline system.or DAPL.
The Partnership accounts for its investment in MarEn Bakken as an equity method investment and bases the equity method accounting for this joint venture in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 is approximately $520 million and reported under the caption Equity method(2) Some investments on the Consolidated Balance Sheets. In connection with the Partnership’s acquisition of a partial, indirect equity interest in the Bakken Pipeline system, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters, beginning with distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated to $0.8 million from the acquisition date.
Acquisition of Hardin Street Marine LLC
On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, MPLX Logistics and MPC Investment, each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million consisting of a fixed number of common units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain MPC’s two percent GP Interest in the Partnership. The acquisition closed on March 31, 2016 and the fair value of the common units and general partner units issued was $669 million and $14 million, respectively, as recorded on the Consolidated Statements of Equity. MPC agreed to waive distributions in the first quarter of 2016 on common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general partner distributions or IDRs that would included within Other have otherwise accrued on such common units with respect to the first quarter 2016 distributions. The value of these waived distributions was $15 million.
The inland marine business, comprised of 18 tow boats and 219 owned and leased barges as of the acquisition date, which transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the Midwest and Gulf Coast regions of the United States, accounted for nearly 60 percent of the total volumes MPC shipped by inland marine vessels as of March 31, 2016. The Partnership accounts for HSM within its L&S segment.
4. Investments and Noncontrolling Interests
Summarized financial information for the Partnership’s equity method investments for the nine months ended September 30, 2017 and 2016 is as follows:
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
(In millions) | MarkWest Utica EMG | | Other VIEs | | Non-VIEs | | Total |
Revenues and other income | $ | 137 |
| | $ | 49 |
| | $ | 178 |
| | $ | 364 |
|
Costs and expenses | 72 |
| | 29 |
| | 115 |
| | 216 |
|
Income from operations | 65 |
| | 20 |
| | 63 |
| | 148 |
|
Net income | 65 |
| | 19 |
| | 28 |
| | 112 |
|
Income from equity method investments(1) | 6 |
| | 7 |
| | 16 |
| | 29 |
|
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(In millions) | MarkWest Utica EMG | | Other VIEs(2) | | Non-VIEs | | Total |
Revenues and other income | $ | 165 |
| | $ | 13 |
| | $ | 108 |
| | $ | 286 |
|
Costs and expenses | 70 |
| | 107 |
| | 80 |
| | 257 |
|
Income (loss) from operations | 95 |
| | (94 | ) | | 28 |
| | 29 |
|
Net income (loss) | 94 |
| | (94 | ) | | 28 |
| | 28 |
|
Income (loss) from equity method investments(1) | 10 |
| | (88 | ) | | 6 |
| | (72 | ) |
| |
(1) | Income (loss) from equity method investments includes the impact of any basis differential amortization or accretion.
|
| |
(2) | Includes an impairment charge of $89 million for the nine months ended September 30, 2016 related to the Partnership’s investment in Ohio Condensate Company, L.L.C., which does not appear separately in this table. |
Summarized balance sheet information for the Partnership’s equity method investments as of September 30, 2017 and December 31, 2016 is as follows:
|
| | | | | | | | | | | | | | | |
| September 30, 2017 |
(In millions) | MarkWest Utica EMG(1) | | Other VIEs | | Non-VIEs | | Total |
Current assets | $ | 72 |
| | $ | 47 |
| | $ | 379 |
| | $ | 498 |
|
Noncurrent assets | 2,092 |
| | 878 |
| | 4,614 |
| | 7,584 |
|
Current liabilities | 37 |
| | 55 |
| | 492 |
| | 584 |
|
Noncurrent liabilities | 2 |
| | 12 |
| | 562 |
| | 576 |
|
|
| | | | | | | | | | | | | | | |
| December 31, 2016 |
(In millions) | MarkWest Utica EMG(1) | | Other VIEs | | Non-VIEs | | Total |
Current assets | $ | 45 |
| | $ | 2 |
| | $ | 40 |
| | $ | 87 |
|
Noncurrent assets | 2,173 |
| | 132 |
| | 390 |
| | 2,695 |
|
Current liabilities | 30 |
| | 4 |
| | 26 |
| | 60 |
|
Noncurrent liabilities | 2 |
| | 13 |
| | — |
| | 15 |
|
| |
(1) | MarkWest Utica EMG, L.L.C.’s (“MarkWest Utica EMG”) noncurrent assets include its investment in its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), which does not appear elsewhere in this table. The investment was $794 million as of September 30, 2017 and December 31, 2016. |
As of September 30, 2017 and December 31, 2016, the carrying value of the Partnership’s equity method investments exceeded the underlying net assets of its investees by $1.1 billion. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $459 million of excess related to goodwill.
MarkWest Utica EMG
Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”), and EMG Utica, LLC (“EMG Utica” and together with Utica Operating, the “Members”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. The related limited liability company agreement hasalso been amended from time to time (the limited liability company agreement currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million. Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until the aggregate capital that had been contributed by the Members reached $2.0 billion, which occurred prior to the MarkWest Merger. Until such time as the investment balances of Utica Operating and EMG Utica are in the ratio of 70 percent and 30 percent, respectively (such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the obligation, to fund up to 10 percent of each capital call for MarkWest Utica EMG, and Utica Operating will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of September 30, 2017, EMG Utica has contributed approximately $1.2 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.
Under the Amended LLC Agreement, prior to December 31, 2016, EMG Utica’s investment balance was increased by a quarterly special non-cash allocation of income (“Preference Amount”), calculated based upon the amount of capital contributed by EMG Utica in excess of $500 million. After December 31, 2016, no Preference Amount will accrue to EMG Utica’s investment balance. EMG Utica received a Preference Amount totaling approximately $4 million and $12 million for the three and nine months ended September 30, 2016, respectively.
Under the Amended LLC Agreement, after December 31, 2016, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of September 30, 2017, Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent.
MarkWest Utica EMG is deemed to be a VIE. Utica Operating is notVIEs.
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 EMG Utica’s voting rights on significant matters. The Partnership’s investmentWhile we have the ability to exercise influence through participation in MarkWest Utica EMG’s,the management committees which was $2.2 billion at September 30, 2017make all significant decisions, we have equal influence over each committee as a joint interest partner and December 31, 2016, is reported underall significant decisions require the caption Equityconsent 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 on the Consolidated Balance Sheets. The Partnership’s in each entity.
MPLX’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMGequity 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. The PartnershipMPLX did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the three and nine months ended September 30, 2017 and 2016, respectively. The Partnership receives management fee revenue for engineering and construction and administrative services for operating MarkWest Utica EMG, and is also reimbursed for personnel services (“Operational Service revenue”). Operational Service revenue is reported as Other income-related parties in the Consolidated Statements of Income. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2017, totaled $5 million and $13 million, respectively. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, respectively.
Ohio Gathering
Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Ohio Gathering is a joint venture between MarkWest Utica EMG and Summit Midstream Partners, LLC. As of September 30, 2017, the Partnership has an approximate 34 percent indirect ownership interest in Ohio Gathering. As Ohio Gathering is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, the Partnership reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational Service revenue for operating Ohio Gathering which is reported as Other income-related parties in the Consolidated Statements of Income. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2017, totaled $4 million and $12 million, respectively. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, respectively.
Sherwood Midstream
Effective January 1, 2017, MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”), a wholly-owned and consolidated subsidiary of MarkWest, and Antero Midstream Partners, LP (“Antero Midstream”) formed a joint venture, Sherwood Midstream LLC (“Sherwood Midstream”), to support Antero Resources Corporation’s development in the Marcellus Shale. MarkWest Liberty Midstream has a 50 percent ownership interest in Sherwood Midstream. Pursuant to the terms of the related limited liability company agreement (the “LLC Agreement”), MarkWest Liberty Midstream contributed assets then under construction with a fair value of approximately $134 million and cash of approximately $20 million. Antero Midstream made an initial capital contribution of approximately $154 million.
Also effective January 1, 2017, MarkWest Liberty Midstream converted all of its ownership interests in MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a previously wholly-owned subsidiary, to Class A Interests and amended its LLC Agreement to create Class B-3 Interests, which were sold to Sherwood Midstream for $126 million in cash. The Class B-3 Interests provide Sherwood Midstream with the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator. Sherwood Midstream accounts for its investment in Ohio Fractionation, which is a VIE, as an equity method investment as Sherwood Midstream does not control Ohio Fractionation. MarkWest Liberty Midstream has been deemed to be the primary beneficiary of Ohio Fractionation because it has control over the decisions that could significantly impact its financial performance, and as a result, consolidates Ohio Fractionation. The carrying amounts of assets and liabilities included in the Partnership’s Consolidated Balance Sheets pertaining to Ohio Fractionation at September 30, 2017, were current assets of $51 million, non-current assets of $406 million and current liabilities of $26 million. The creditors of Ohio Fractionation do not have recourse to MPLX LP’s general credit through guarantees or other financial arrangements. The assets of Ohio Fractionation are the property of Ohio Fractionation and cannot be used to satisfy the obligations of MPLX LP. Sherwood Midstream’s interests are reflected in Net income attributable to noncontrolling interests in the Consolidated Statements of Income and Noncontrolling interests in the Consolidated Balance Sheets.
Under the LLC Agreement, cash generated by Sherwood Midstream that is available for distribution will be allocated to the members in proportion to their respective investment balances.
Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary beneficiary, due to Antero Midstream’s voting rights on significant matters. The Partnership’s investment in Sherwood Midstream, which was approximately $220 million at September 30, 2017, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream 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. The Partnership did not provide any financial support to Sherwood Midstream that it was not contractually obligated to provide during the nine months ended September 30, 2017. The Partnership receives Operational Service revenue2023. See Note 15 for operating Sherwood Midstream. The amount of Operational Service revenueinformation on our Guarantees related to Sherwood Midstream for the three and nine months ended September 30, 2017, totaled approximately $2 million and $6 million, respectively, and is reported as Other income-related parties in the Consolidated Statementsindebtedness of Income.
Sherwood Midstream Holdings
Effective January 1, 2017, MarkWest Liberty Midstream and Sherwood Midstream formed a joint venture, Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), for the purpose of owning, operating and maintaining all of the shared assets that support the operations of the gas plants and other assets owned by Sherwood Midstream and the gas plants and deethanization facilities owned by MarkWest Liberty Midstream. MarkWest Liberty Midstream initially contributed certain real property, equipment and facilities with a fair value of approximately $209 million to Sherwood Midstream Holdings in exchange for a 79 percent initial ownership interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings in exchange for a 21 percent ownership interest. During the second quarter ended June 30, 2017, true-ups to the initial contributions were finalized. MarkWest Liberty Midstream contributed certain additional real property, equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings. Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net book value of the contributed assets was approximately $203 million. The contribution was determined to be an in-substance sale of real estate. As such, the Partnership only recognized a gain for the portion attributable to Antero Midstream’s indirect interest of approximately $2 million, included in Gain on sale of assets in the Consolidated Statements of Income. MarkWest Liberty Midstream’s portion of the gain attributable to its direct and indirect interests of approximately $14 million is included in its investment in Sherwood
Midstream Holdings and is reported under the caption Equity method investments on the Consolidated Balance Sheets. In connection with the initial contributions, MarkWest Liberty Midstream received a special distribution of approximately $45 million.
MarkWest Liberty Midstream’s and Sherwood Midstream’s ownership interests in Sherwood Midstream Holdings will fluctuate over time. As new Shared Assets are constructed, the members will make additional capital contributions to Sherwood Midstream Holdings. The amount that each member must contribute will be based on the expected utilization of the Shared Assets, as defined in the LLC Agreement. Pursuant to the terms of the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.
The Partnership accounts for Sherwood Midstream Holdings, which is a VIE, as an equity method investment as Sherwood Midstream is considered to be the general partner and controls all decisions. The Partnership’s investment in Sherwood Midstream Holdings, which was approximately $163 million at September 30, 2017, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream Holdings 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. The Partnership did not provide any financial support to Sherwood Midstream Holdings that it was not contractually obligated to provide during the nine months ended September 30, 2017.investees.
Sherwood Midstream has been deemed the primary beneficiary of Sherwood Midstream Holdings due to its controlling financial interest through its authority to manage the joint venture. As a result, Sherwood Midstream consolidates Sherwood Midstream Holdings. Therefore, the Partnership also reports its portion of Sherwood Midstream Holdings’ net assets as a component of its investment in Sherwood Midstream. As of September 30, 2017, the Partnership has a 14.7 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.
5.4. Related Party Agreements and Transactions
The Partnership’s materialMPLX 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 include:are further described below.
MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States.
Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent interest as of September 30, 2017. Centennial owns a products pipeline and storage facility.
Muskegon Pipeline LLC (“Muskegon”), in which MPC has a 60 percent interest as of September 30, 2017. Muskegon owns a common carrier products pipeline.
MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of September 30, 2017. MarkWest Utica EMG is engaged in natural gas processing and NGL fractionation, transportation and marketing in Ohio.
Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of September 30, 2017. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.
Sherwood Midstream, in which MPLX LP has a 50 percent interest as of September 30, 2017. Sherwood Midstream supports the development of Antero Resources Corporation’s Marcellus Shale acreage in the rich-gas corridor of West Virginia.
Sherwood Midstream Holdings, in which MPLX LP has an 86 percent total direct and indirect interest as of September 30, 2017. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood Complex that is shared by and supports the operation of both the Sherwood Midstream and MarkWest gas processing plants and deethanization facilities.
Illinois Extension, in which MPLX LP has a 35 percent interest as of September 30, 2017. Illinois Extension operates the SAX crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations.
LOOP, in which MPLX LP has a 40.7 percent interest as of September 30, 2017. LOOP owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana, pipelines, and onshore storage facilities, and manages operations of LOCAP, an affiliate pipeline system.
LOCAP, in which MPLX LP has a 58.52 percent interest as of September 30, 2017. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the midcontinent region of the United States.
Explorer, in which MPLX LP has a 24.51 percent interest as of September 30, 2017. Explorer owns and operates a common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining complex to the Midwestern United States.
Related Party Agreements
The Partnership has various long-term, fee-based commercial agreements with MPC. Under these agreements, the PartnershipMPLX provides transportation, gathering, terminal, fuels distribution, marketing, storage, management, operational and storageother services to MPC, andMPC. MPC has committed to provide the PartnershipMPLX with minimum quarterly throughput volumes on crude oil and refined products systems and minimumother fees for storage volumescapacity; operating and management fees; and reimbursements for certain direct and indirect costs. MPC has also committed to provide a fixed fee for 100 percent of crude oil, refined productsavailable capacity for boats, barges and butane.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
In addition,behalf. We pay MPC a marketing fee in exchange for assuming the Partnershipcommodity risk. Additionally, MPLX has obligations to 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 Investment, a wholly-owned subsidiary of MPC. Under the terms of the agreement, MPC Investment will make a loan orLoan Agreement, MPC extends loans to the PartnershipMPLX on a revolving basis as requested by the PartnershipMPLX and as agreed to by MPC. The borrowing capacity of the MPC Investment, in an amount or amounts that do not result in theLoan Agreement is $1.5 billion aggregate principal amount of all loans outstanding exceeding $500 million at any one time. The entire unpaid principal amount ofMPC Loan Agreement is scheduled to expire, and borrowings under the loan together with all accruedagreement are scheduled to mature and unpaid interest and other amounts (if any), shall become due and payable, on December 4, 2020.July 31, 2024, provided that MPC Investment may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to December 4, 2020.maturity. Borrowings under the loan willMPC Loan Agreement bear interest at LIBORone-month term SOFR adjusted upward by 0.10 percent plus 1.50 percent. During1.25 percent or such lower rate as would be applicable to such loans under the nine months ended September 30, 2017, the Partnership borrowed $829 million and repaid $627 million, resultingMPLX Credit Agreement as discussed in $202 million outstanding balance at September 30, 2017, which is included in Payables-related partiesNote 11.
There was no activity on the Consolidated Balance Sheets. Borrowings were at an average interest rate of 2.721 percent, per annum,MPC Loan Agreement for the nine months ended September 30, 2017. During the year ended December 31, 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no outstanding balance at December 31, 2016. Borrowings were at an average interest rate of 1.939 percent, per annum, for the year ended December 31, 2016. For additional information regarding the Partnership’s commercial and other agreements with MPC, see Item 1. Business in the Annual Report on Form 10-K for the year ended December 31, 2016.2023.
The Partnership believes the terms and conditions under its agreements with MPC are generally comparable to those with unrelated parties.
HST, WHC and MPLXT Agreements
As discussed in Note 3, the Partnership acquired HST, WHC and MPLXT on March 1, 2017. HST, WHC and MPLXT have various operating, transportation services, terminal services, storage services and employee services agreements with MPC, which were assumed by the Partnership with the closing of the Transaction.
HST is a party to a transportation services agreement with MPC dated January 1, 2015. Under this agreement, HST provides pipeline transportation of crude oil and refined products, as well as related services, for MPC. MPC pays HST for such services based on contractual rates related to MPC crude oil and refined product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on December 31, 2026 and automatically renews for two additional renewal terms of four years each unless terminated by either party.
On January 1, 2015, HST entered into various three-year term storage services agreements with MPC. Under the storage services agreements, HST receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage tank. The contractual rate per barrel is subject to an annual review and adjustment for inflation. HST is not obligated to measure volume gains and losses per the terms of these agreements.
On January 1, 2015, WHC entered into a long-term, fee-based storage and services agreement with MPC related to storage at its butane and propane caverns with an initial term of 10 years. Under this storage and services agreement, WHC receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage cavern. The contractual rate per barrel includes utilization of the caverns and related services. The agreement is subject to an annual review and adjustment for inflation.
Under the storage services agreements with both HST and WHC, the Partnership is obligated to make available to MPC, on a firm basis, the available storage capacity at the tank farms and butane and propane caverns and MPC pays the Partnership a per-barrel fee for such storage capacity regardless of whether MPC fully utilizes the available capacity.
MPLXT is a party to a terminal services agreement with MPC, dated March 1, 2017. Under this agreement, MPLXT provides terminal storage for refined petroleum products, as well as related services, for MPC. MPC pays MPLXT monthly for such services based on contractual fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on March 31, 2026 and automatically renews for two additional renewal terms of five years each unless terminated by either party.
The Partnership is party to various employee services agreements with MPC under which the Partnership reimburses MPC for employee benefit expenses, along with the provision of operational and management services, including those in support of HST, WHC and MPLXT.
Related Party TransactionsRevenue
Sales to related parties were as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Service revenues | | | | | | | |
MPC | $ | 276 |
| | $ | 253 |
| | $ | 801 |
| | $ | 676 |
|
Rental income | | | | | | | |
MPC | $ | 70 |
| | $ | 68 |
| | $ | 207 |
| | $ | 172 |
|
Product sales(1) | | | | | | | |
MPC | $ | 2 |
| | $ | 2 |
| | $ | 6 |
| | $ | 8 |
|
| |
(1) | There were additional product sales to MPC that net to zero within the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For the three and nine months ended September 30, 2017, these sales totaled $63 million and $173 million, respectively. For the three and nine months ended September 30, 2016, these sales totaled $13 million and $25 million, respectively. |
Related party sales to MPC primarily consist of crude oil and refined products pipeline transportation services based on regulated tariff rates,or contracted rates; storage, terminal and fuels distribution services based on contracted ratesrates; 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 nine months ended September 30, 2023, these sales totaled $192 million and $540 million, respectively. For the three and nine months ended September 30, 2022, these sales totaled $235 million and $809 million, respectively.
Related Party Expenses
MPC charges MPLX for executive management services and certain general and administrative services provided by HSM. Underto MPLX under the Partnership’s pipeline transportationterms of our omnibus agreements (“Omnibus charges”) and for certain employee services provided to MPLX under employee services agreements if(“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 nine months ended September 30, 2023, General and administrative expenses incurred from MPC totaled $72 million and $197 million, respectively. For the three and nine months ended September 30, 2022, General and administrative expenses incurred from MPC totaled $60 million and $173 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 nine months ended September 30, 2023, these charges totaled $28 million and $56 million, respectively. For the three and nine months ended September 30, 2022, these charges totaled $16 million and $54 million, respectively.
Related Party Assets and Liabilities
Assets and liabilities with related parties appearing in the Consolidated Balance Sheets are detailed in the table below. This table identifies the various components of related party assets and liabilities, including those associated with leases and deferred revenue on minimum volume commitments. If MPC fails to transportmeet its minimum throughputcommitted volumes, during any quarter, then MPC will pay the PartnershipMPLX a deficiency payment equal tobased on the volumeterms of the deficiency multiplied by the tariff rate then in effect.agreement. The deficiency amounts received under these agreements (excluding payments received under agreements classified as sales-type leases) are recorded as Deferred revenue-related parties.Current liabilities - related parties. In many cases, MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quartersin future periods under the terms of the applicable transportation services agreement. The Partnershipagreements. MPLX recognizes related party revenues for the deficiency payments when credits are used for volumes transported in excess of minimum quarterly volume commitments, whenwhere it becomes impossible to physically transport volumes necessary to utilizeis
probable the creditscustomer will not use the credit in future periods or upon the expiration of the credits. The use or expiration of the credits is a decrease in Deferred revenue-related parties.
The revenue received fromCurrent liabilities - related parties, included in Other income-related parties on the Consolidated Statements of Income, was as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
MPC | $ | 9 |
| | $ | 10 |
| | $ | 30 |
| | $ | 36 |
|
MarkWest Utica EMG | 5 |
| | 5 |
| | 13 |
| | 12 |
|
Ohio Gathering | 4 |
| | 5 |
| | 12 |
| | 12 |
|
Other | 4 |
| | 2 |
| | 14 |
| | 7 |
|
Total | $ | 22 |
| | $ | 22 |
| | $ | 69 |
| | $ | 67 |
|
MPC provides executive management services and certain general and administrative services to the Partnershipparties. Deficiency payments under the terms of an omnibus agreement. Expenses incurred under this agreement are shown in the table below by the income statement line where they were recorded. Charges for services included in Purchases-related parties primarily relate to servicesagreements that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Purchases - related parties | $ | 17 |
| | $ | 11 |
| | $ | 50 |
| | $ | 29 |
|
General and administrative expenses | 9 |
| | 11 |
| | 28 |
| | 33 |
|
Total | $ | 26 |
| | $ | 22 |
| | $ | 78 |
| | $ | 62 |
|
Also under terms of the omnibus agreement, some service costs related to engineering services are associated with assets under construction. These costs added to Property, plant and equipment were as follows:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
MPC | $ | 11 |
| | $ | 14 |
| | $ | 33 |
| | $ | 36 |
|
MPLX LP obtains employee services from MPC under employee services agreements. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. The costs of personnel directly involved in or supporting operations and maintenance activities arehave been classified as Purchases-related parties. The costs of personnel involved in executive management, accounting and human resources activitiessales-type leases are classifiedrecorded as General and administrative expenses ina reduction against the Consolidated Statements of Income.
Employee services expenses from related parties were as follows: |
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Purchases - related parties | $ | 97 |
| | $ | 98 |
| | $ | 280 |
| | $ | 257 |
|
General and administrative expenses | 25 |
| | 27 |
| | 74 |
| | 75 |
|
Total | $ | 122 |
| | $ | 125 |
| | $ | 354 |
| | $ | 332 |
|
Receivables from related parties, which for December 31, 2016 included reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units, were as follows:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
MPC | $ | 144 |
| | $ | 242 |
|
MarkWest Utica EMG | 2 |
| | 2 |
|
Ohio Gathering | 2 |
| | 2 |
|
Other | 4 |
| | 1 |
|
Total | $ | 152 |
| | $ | 247 |
|
Long-term receivables with related parties, which includes straight-line rental income, were as follows:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
MPC | $ | 18 |
| | $ | 11 |
|
Payables to related parties were as follows:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
MPC(1) | $ | 277 |
| | $ | 63 |
|
MarkWest Utica EMG | 30 |
| | 24 |
|
Other | 10 |
| | — |
|
Total | $ | 317 |
| | $ | 87 |
|
| |
(1) | Balance includes approximately $202 million related to the loan with MPC Investment as discussed above. |
During the nine months ended September 30, 2017 and the year ended December 31, 2016, MPC did not ship its minimum committed volumes on certain pipeline systems.corresponding lease receivable. In addition, capital projects the Partnership is undertakingMPLX undertakes at the request of MPC are reimbursed in cash and recognized in incomeas revenue over the remaining term of the applicable agreements. The Deferred revenue-related parties balance associated withagreements or in some cases, as a contribution from MPC.
| | | | | | | | | | | |
(In millions) | September 30, 2023 | | December 31, 2022 |
Current assets - related parties | | | |
Receivables | $ | 599 | | | $ | 610 | |
Lease receivables | 140 | | | 111 | |
Prepaid | 14 | | | 5 | |
Other | 6 | | | 3 | |
Total | 759 | | | 729 | |
Noncurrent assets - related parties | | | |
Long-term lease receivables | 811 | | | 883 | |
Right of use assets | 227 | | | 228 | |
Unguaranteed residual asset | 115 | | | 87 | |
Long-term receivables | 21 | | | 27 | |
Total | 1,174 | | | 1,225 | |
Current liabilities - related parties | | | |
MPC loan agreement and other payables(1) | 312 | | | 262 | |
Deferred revenue | 74 | | | 80 | |
Operating lease liabilities | 1 | | | 1 | |
Total | 387 | | | 343 | |
Long-term liabilities - related parties | | | |
Long-term operating lease liabilities | 226 | | | 228 | |
Long-term deferred revenue | 117 | | | 110 | |
Total | $ | 343 | | | $ | 338 | |
(1) There were no borrowings outstanding on the minimum volume deficiencies and project reimbursements wereMPC Loan Agreement as follows:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
Minimum volume deficiencies - MPC | $ | 55 |
| | $ | 48 |
|
Project reimbursements - MPC | 27 |
| | 9 |
|
Total | $ | 82 |
| | $ | 57 |
|
6. Net Income (Loss) Per Limited Partner Unit
Net income (loss) per unit applicable to common limited partner units is computed by dividing the respective limited partners’ interest in net income (loss) attributable to MPLX LP by the weighted average number of common units outstanding. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income (loss) per unit applicable to limited partners. The classes of participating securities include common units, general partner units, Preferred units, certain equity-based compensation awards and IDRs.
As discussed in Note 1, the HST, WHC and MPLXT acquisition was a transfer between entities under common control. As entities under common control with MPC, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings have been allocated to the general partner and do not affect the net income (loss) per unit calculation. The earnings for the entities acquired under common control will be included in the net income (loss) per unit calculation prospectively as described above.
For the three months ended September 30, 2017,2023 or December 31, 2022.
Other Related Party Transactions
From time to time, MPLX may also sell to or purchase from related parties, assets and inventory at the Partnership had dilutive potential common units consistinglesser of certain equity-based compensation awards. For the three months ended September 30, 2016 and the nine months ended September 30, 2017 and 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Potential common units omitted from the diluted earnings peraverage unit calculation for the three and nine months ended September 30, 2017 were less than one million and for the three and nine months ended September 30, 2016 were less than one million and approximately eight million, respectively.cost or net realizable value.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Net income attributable to MPLX LP | $ | 216 |
| | $ | 141 |
| | $ | 556 |
| | $ | 100 |
|
Less: Limited partners’ distributions declared on Preferred units(1) | 16 |
| | 16 |
| | 49 |
| | 25 |
|
General partner’s distributions declared (including IDRs)(1) | 88 |
| | 54 |
| | 229 |
| | 148 |
|
Limited partners’ distributions declared on common units(1) | 232 |
| | 179 |
| | 648 |
| | 507 |
|
Undistributed net loss attributable to MPLX LP | $ | (120 | ) |
| $ | (108 | ) | | $ | (370 | ) | | $ | (580 | ) |
| |
(1) | See Note 7 for distribution information. |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
(In millions, except per unit data) | General Partner | | Limited Partners’ Common Units | | Redeemable Preferred Units | | Total |
Basic and diluted net income attributable to MPLX LP per unit: | | | | | | | |
Net income attributable to MPLX LP: | | | | | | | |
Distributions declared (including IDRs) | $ | 88 |
| | $ | 232 |
| | $ | 16 |
| | $ | 336 |
|
Undistributed net loss attributable to MPLX LP | (2 | ) | | (118 | ) | | — |
| | (120 | ) |
Net income attributable to MPLX LP(1) | $ | 86 |
| | $ | 114 |
| | $ | 16 |
| | $ | 216 |
|
Weighted average units outstanding: | | | | | | | |
Basic | 8 |
| | 394 |
| | 31 |
| | 433 |
|
Diluted | 8 |
| | 395 |
| | 31 |
| | 434 |
|
Net income attributable to MPLX LP per limited partner unit: | | | | | | | |
Basic | | | $ | 0.29 |
| | | | |
Diluted | | | $ | 0.29 |
| | | | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2016 |
(In millions, except per unit data) | General Partner | | Limited Partners’ Common Units | | Redeemable Preferred Units | | Total |
Basic and diluted net income attributable to MPLX LP per unit: | | | | | | | |
Net income attributable to MPLX LP: | | | | | | | |
Distributions declared (including IDRs) | $ | 54 |
| | $ | 179 |
| | $ | 16 |
| | $ | 249 |
|
Undistributed net loss attributable to MPLX LP | (3 | ) | | (105 | ) | | — |
| | (108 | ) |
Net income attributable to MPLX LP(1) | $ | 51 |
| | $ | 74 |
| | $ | 16 |
| | $ | 141 |
|
Weighted average units outstanding: | | | | | | | |
Basic | 7 |
| | 341 |
| | 31 |
| | 379 |
|
Diluted | 7 |
| | 346 |
| | 31 |
| | 384 |
|
Net income attributable to MPLX LP per limited partner unit: | | | | | | | |
Basic | | | $ | 0.22 |
| |
|
| | |
Diluted | | | $ | 0.21 |
| |
|
| | |
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
(In millions, except per unit data) | General Partner | | Limited Partners’ Common Units | | Redeemable Preferred Units | | Total |
Basic and diluted net income attributable to MPLX LP per unit: | | | | | | | |
Net income attributable to MPLX LP: | | | | | | | |
Distributions declared (including IDRs) | $ | 229 |
| | $ | 648 |
| | $ | 49 |
| | $ | 926 |
|
Undistributed net loss attributable to MPLX LP | (7 | ) | | (363 | ) | | — |
| | (370 | ) |
Net income attributable to MPLX LP(1) | $ | 222 |
| | $ | 285 |
| | $ | 49 |
| | $ | 556 |
|
Weighted average units outstanding: | | | | | | | |
Basic | 8 |
| | 378 |
| | 31 |
| | 417 |
|
Diluted | 8 |
| | 381 |
| | 31 |
| | 420 |
|
Net income attributable to MPLX LP per limited partner unit: | | | | | | | |
Basic | | | $ | 0.75 |
| | | | |
Diluted | | | $ | 0.75 |
| | | | |
|
| | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(In millions, except per unit data) | General Partner | | Limited Partners’ Common Units | | Redeemable Preferred Units | | Total |
Basic and diluted net loss attributable to MPLX LP per unit: | | | | | | | |
Net income (loss) attributable to MPLX LP: | | | | | | | |
Distributions declared (including IDRs) | $ | 148 |
| | $ | 507 |
| | $ | 25 |
| | $ | 680 |
|
Undistributed net loss attributable to MPLX LP | (12 | ) | | (568 | ) | | — |
| | (580 | ) |
Net income (loss) attributable to MPLX LP(1) | $ | 136 |
| | $ | (61 | ) | | $ | 25 |
| | $ | 100 |
|
Weighted average units outstanding: | | | | | | | |
Basic | 7 |
| | 324 |
| | 16 |
| | 347 |
|
Diluted | 7 |
| | 324 |
| | 16 |
| | 347 |
|
Net loss attributable to MPLX LP per limited partner unit: | | | | | | | |
Basic | | | $ | (0.19 | ) | |
|
| | |
Diluted | | | $ | (0.19 | ) | |
|
| | |
| |
(1) | Allocation of net income (loss) attributable to MPLX LP assumes all earnings for the period had been distributed based on the current period distribution priorities. |
7.5. Equity
The changes in the number of common units outstanding during the nine months ended September 30, 20172023 are summarized below:
|
| | | | | | | | | | | |
(In units) | Common | | Class B | | General Partner | | Total |
Balance at December 31, 2016 | 357,193,288 |
| | 3,990,878 |
| | 7,371,105 |
| | 368,555,271 |
|
Unit-based compensation awards(1) | 183,509 |
| | — |
| | 3,745 |
| | 187,254 |
|
Issuance of units under the ATM Program(2) | 13,846,998 |
| | — |
| | 282,591 |
| | 14,129,589 |
|
Contribution of HST/WHC/MPLXT(3) | 12,960,376 |
| | — |
| | 264,497 |
| | 13,224,873 |
|
Contribution of the Joint-Interest Acquisition(3) | 18,511,134 |
| | — |
| | 377,778 |
| | 18,888,912 |
|
Class B conversion(4) | 4,350,057 |
| | (3,990,878 | ) | | 7,330 |
| | 366,509 |
|
Balance at September 30, 2017 | 407,045,362 |
|
| — |
|
| 8,307,046 |
|
| 415,352,408 |
|
| | | | | | | | | | | |
(1)(In units) | As a result of the unit-based compensation awards issued during the period, MPLX GP contributed less than $1 million in exchange for 3,745 general partner units to maintain its two percent GP Interest.Common Units |
| | | | | |
(2)Balance at December 31, 2022 | As a result of common units issued under the ATM Program during the period, MPLX GP contributed $10 million in exchange for 282,591 general partner units to maintain its two percent GP Interest.1,001,020,616 |
| | | | | | |
(3)Unit-based compensation awards | See Note 3 for information regarding this acquisition.196,428 |
| | | | | | |
(4) | On July 1, 2017, 3,990,878 Class B units converted to 4,350,057 common units and were eligible to receive the second quarter 2017 distribution. As a result of the Class B conversion, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent GP Interest. | | | | | | |
Balance at September 30, 2023 | 1,001,217,044 | | | | | | | |
Reorganization Transactions –
Unit Repurchase Program
On August 2, 2022, we announced the board authorization for the repurchase of up to $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 nine months ended September 1, 2016,30, 2023. As of September 30, 2023, we had $846 million remaining under the Partnershipunit repurchase authorization.
Redemption of the Series B Preferred Units
On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding 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 various affiliates initiated a seriesAugust of reorganization transactions in ordereach year up to simplify the Partnership’s ownership structure and its financial and tax reporting requirements.including February 15, 2023. In connectionaccordance with these transactions, the issued and outstandingterms, MPLX LP Class A units, allmade a final cash distribution of which were held by MarkWest Hydrocarbon, were either distributed to or purchased by MPC in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner units. Following these initial transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing limited partner interests in MPLX LP. MPC also contributed $141$21 million to facilitateSeries B preferred unitholders on February 15, 2023, in conjunction with the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treatedredemption.
The changes in the same manner as cash derived from or attributable to other operations ofSeries B preferred unit balance during the Partnershipnine months ended September 30, 2023 and its subsidiaries.
Net Income Allocation–In preparingSeptember 30, 2022 are included in the Consolidated Statements of Equity net income (loss) attributable towithin Series B preferred units.
Distributions
On October 24, 2023, MPLX LP is allocated to Preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to the general partner and limited partner unitholders. However, when distributions related to the IDRs are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders, based on their respective ownership percentages. The following table presents the allocation of the general partner’s GP Interest in net income attributable to MPLX LP:
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Net income attributable to MPLX LP | $ | 216 |
| | $ | 141 |
| | $ | 556 |
| | $ | 100 |
|
Less: Preferred unit distributions | 16 |
| | 16 |
| | 49 |
| | 25 |
|
General partner's IDRs and other | 83 |
| | 49 |
| | 216 |
| | 137 |
|
Net income (loss) attributable to MPLX LP available to general and limited partners | $ | 117 |
| | $ | 76 |
| | $ | 291 |
| | $ | (62 | ) |
| | | | | | | |
General partner's two percent GP Interest in net income (loss) attributable to MPLX LP | $ | 3 |
| | $ | 2 |
| | $ | 6 |
| | $ | (1 | ) |
General partner's IDRs and other | 83 |
| | 49 |
| | 216 |
| | 137 |
|
General partner's GP Interest in net income attributable to MPLX LP | $ | 86 |
| | $ | 51 |
| | $ | 222 |
| | $ | 136 |
|
Cash distributions–The Partnership Agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Preferred unitholders and general partner will receive. In accordance with the Partnership Agreement, on October 25, 2017, the Partnership declared a quarterly cash distribution based on the results offor the third quarter of 2017,2023, totaling $320$851 million, or $0.5875$0.850 per common unit. These distributionsThis distribution will be paid on November 14, 201713, 2023 to common unitholders of record on November 6, 2017.3, 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, | $ | 0.775 | | | $ | 0.705 | |
June 30, | 0.775 | | | 0.705 | |
September 30, | $ | 0.850 | | | $ | 0.775 | |
The allocation of total quarterly cash distributions to general, limited and Preferredpreferred unitholders is as follows for the three and nine months ended September 30, 20172023 and 2016. The Partnership’sSeptember 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 September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
Common and preferred unit distributions: | | | | | | | |
Common unitholders, includes common units of general partner | $ | 851 | | | $ | 777 | | | $ | 2,403 | | | $ | 2,204 | |
Series A preferred unit distributions | 25 | | | 23 | | | 71 | | | 65 | |
Series B preferred unit distributions(1) | — | | | 10 | | | 5 | | | 31 | |
Total cash distributions declared | $ | 876 | | | $ | 810 | | | $ | 2,479 | | | $ | 2,300 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
General partner's distributions: | | | | | | | |
General partner's distributions on general partner units | $ | 7 |
| | $ | 5 |
| | $ | 18 |
| | $ | 13 |
|
General partner's distributions on IDRs | 81 |
| | 49 |
| | 211 |
| | 135 |
|
Total distribution on general partner units and IDRs | $ | 88 |
| | $ | 54 |
| | $ | 229 |
| | $ | 148 |
|
Common and preferred unit distributions: | | | | | | | |
Common unitholders, includes common units of general partner | $ | 232 |
| | $ | 179 |
| | $ | 648 |
| | $ | 507 |
|
Preferred unit distributions | 16 |
| | 16 |
| | 49 |
| | 25 |
|
Total cash distributions declared | $ | 336 |
| | $ | 249 |
| | $ | 926 |
| | $ | 680 |
|
8. Redeemable Preferred Units
Private Placement of Preferred Units –On May 13, 2016, MPLX LP completed(1) The nine months ended September 30, 2023 includes the private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units (the "Preferred units") for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the saleportion of the Preferred units were used for capital expenditures, repayment of debt and general partnership purposes.$21 million distribution paid to the Series B preferred unitholders on February 15, 2023 that was earned during the period prior to redemption.
The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit. Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will receive as a distribution the greater of $0.528125
6. Net Income Per Limited Partner Unit
Net income per unit or the amount of per unit distributions paidapplicable to holders of MPLX LP common units.
The changes in the redeemable preferred balance from December 31, 2016 through September 30, 2017 are summarized below:
|
| | | |
(In millions) | Redeemable Preferred Units |
Balance at December 31, 2016 | $ | 1,000 |
|
Net income | 49 |
|
Distributions received by Preferred unitholders | (49 | ) |
Balance at September 30, 2017 | $ | 1,000 |
|
The holders may convert their Preferred units into common units at any time after the third anniversary of the issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership may convert the Preferred units into common units at any time, in whole or in part, subject to certain minimum conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75computed by dividing net income attributable to MPLX LP less income allocated to participating securities by the weighted average number of common units outstanding.
During the three and nine months ended September 30, 2023 and September 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 20 day trading period immediately preceding the conversion notice date. The conversion ratethree and nine months ended September 30, 2023 andSeptember 30, 2022 were less than 1 million.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
Net income attributable to MPLX LP | $ | 918 | | | $ | 1,428 | | | $ | 2,794 | | | $ | 3,128 | |
Less: Distributions declared on Series A preferred units | 25 | | | 23 | | | 71 | | | 65 | |
| | | | | | | |
Distributions declared on Series B preferred units | — | | | 10 | | | 5 | | | 31 | |
Limited partners’ distributions declared on MPLX common units (including common units of general partner) | 851 | | | 777 | | | 2,403 | | | 2,204 | |
| | | | | | | |
Undistributed net gain attributable to MPLX LP | $ | 42 | | | $ | 618 | | | $ | 315 | | | $ | 828 | |
| | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 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 | $ | 851 | | | | | $ | 25 | | | | | $ | 876 | |
Undistributed net gain attributable to MPLX LP | 41 | | | | | 1 | | | | | 42 | |
Net income attributable to MPLX LP(1) | $ | 892 | | | | | $ | 26 | | | | | $ | 918 | |
| | | | | | | | | |
| | | | | | | | | |
Weighted average units outstanding: | | | | | | | | | |
Basic | 1,001 | | | | | | | | | |
Diluted | 1,001 | | | | | | | | | |
Net income attributable to MPLX LP per limited partner unit: | | | | | | | | | |
Basic | $ | 0.89 | | | | | | | | | |
Diluted | $ | 0.89 | | | | | | | | | |
(1) Allocation of net income attributable to MPLX LP assumes all earnings for the Preferred units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributionsperiod had been distributed based on the distribution priorities applicable Preferred unit, divided by (b) $32.50. The holders of the Preferred units are entitled to vote on an as-converted basis with the common unitholders and will have certain other class voting rights with respect to any amendment to the Partnership Agreement that would adversely affect any rights, preferences or privilegesperiod.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 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 | $ | 777 | | | | | $ | 23 | | | $ | 10 | | | $ | 810 | |
Undistributed net gain attributable to MPLX LP(1) | 600 | | | | | 18 | | | — | | | 618 | |
Net income attributable to MPLX LP(2) | $ | 1,377 | | | | | $ | 41 | | | $ | 10 | | | $ | 1,428 | |
Weighted average units outstanding: | | | | | | | | | |
Basic | 1,010 | | | | | | | | | |
Diluted | 1,011 | | | | | | | | | |
Net income attributable to MPLX LP per limited partner unit: | | | | | | | | | |
Basic | $ | 1.36 | | | | | | | | | |
Diluted | $ | 1.36 | | | | | | | | | |
(1) The undistributed net gain attributable to MPLX LP includes a $509 million non-cash gain on a lease reclassification for the three months ended September 30, 2022. See Note 14 for additional information.
(2) Allocation of net income attributable to MPLX LP assumes all earnings for the Preferred units. In addition, upon certain events involving a change of controlperiod had been distributed based on the holders of Preferred units may elect, among other potential elections,distribution priorities applicable to convert their Preferred units to common units at the then-change of control conversion rate.period.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 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 | $ | 2,403 | | | | | $ | 71 | | | $ | 5 | | | $ | 2,479 | |
Undistributed net gain attributable to MPLX LP | 306 | | | | | 9 | | | — | | | 315 | |
Net income attributable to MPLX LP(1) | 2,709 | | | | | $ | 80 | | | $ | 5 | | | 2,794 | |
Impact of redemption of Series B preferred units | (5) | | | | | | | | | (5) | |
Income available to common unitholders | $ | 2,704 | | | | | | | | | $ | 2,789 | |
Weighted average units outstanding: | | | | | | | | | |
Basic | 1,001 | | | | | | | | | |
Diluted | 1,001 | | | | | | | | | |
Net income attributable to MPLX LP per limited partner unit: | | | | | | | | | |
Basic | $ | 2.70 | | | | | | | | | |
Diluted | $ | 2.70 | | | | | | | | | |
The Preferred units are considered redeemable securities under GAAP due(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 existenceperiod.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Nine Months Ended September 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 | $ | 2,204 | | | | | $ | 65 | | | $ | 31 | | | $ | 2,300 | |
Undistributed net gain attributable to MPLX LP(1) | 804 | | | | | 24 | | | — | | | 828 | |
Net income attributable to MPLX LP(2) | $ | 3,008 | | | | | $ | 89 | | | $ | 31 | | | $ | 3,128 | |
Weighted average units outstanding: | | | | | | | | | |
Basic | 1,012 | | | | | | | | | |
Diluted | 1,013 | | | | | | | | | |
Net income attributable to MPLX LP per limited partner unit: | | | | | | | | | |
Basic | $ | 2.97 | | | | | | | | | |
Diluted | $ | 2.97 | | | | | | | | | |
(1) The undistributed net gain attributable to MPLX LP includes a $509 million non-cash gain on a lease reclassification for the nine months ended September 30, 2022. See Note 14 for additional information.
(2) Allocation of redemption provisions upon a deemed liquidation event which is outsidenet income attributable to MPLX LP assumes all earnings for the Partnership’s control. Therefore, they are presented as temporary equity inperiod had been distributed based on the mezzanine section of the Consolidated Balance Sheets. The Preferred units have been recorded at their issuance date fair value, net of issuance costs. Income allocations increase the carrying value, and declared distributions decreased the carrying value of the Preferred units. As the Preferred units are not currently redeemable and not probable of becoming redeemable, adjustmentdistribution priorities applicable to the initial carrying amount is not necessary and would only be required if it becomes probable that the Preferred units would become redeemable.period.
9.7. Segment Information
The Partnership’sMPLX’s chief operating decision maker (“CODM”) is the chief executive officer (“CEO”) of its general partner. The CEOCODM reviews the Partnership’sMPLX’s discrete financial information, makes operating decisions, assesses financial performance and allocates resources on a type of service basis. The PartnershipMPLX has two reportable segments: L&S and G&P. Each of these segments areis 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 refined petroleum products. Segment information for prior periodsrenewables. Also includes retrospective adjustments in connection with the acquisitionoperation of HST, WHCrefining logistics, fuels distribution and MPLXT. Segment information is not included for periods prior to the Joint-Interest Acquisitioninland marine businesses, terminals, rail facilities, and the Ozark pipeline acquisition. See Note 3 for more detail of these acquisitions.storage caverns.
•G&P – gathers, processes and transports natural gas; gathers,and transports, fractionates, stores and markets NGLs.
The Partnership has investmentsOur CODM evaluates the performance of our segments using Segment Adjusted EBITDA. Amounts included in entities that are accounted for using thenet income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) interest and other financial costs; (iii) income/(loss) from equity method of accounting (see Note 4). However, the CEO views the Partnership-operatedinvestments; (iv) distributions and adjustments related to equity method investments’ financial informationinvestments; (v) gain on sales-type leases; (vi) impairment expense; (vii) noncontrolling interests; and (viii) other adjustments, as if those investments were consolidated.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
Segment operating income represents income from operations attributablenot tied to the reportable segments. Corporate general and administrative expenses, unrealized derivative gains (losses), goodwill impairment, certain management fees and depreciation and amortizationoperational performance of the segment. Assets by segment are not allocateda measure used to assess the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially-owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to Predecessorsperformance of the HSM, HST, WHCPartnership by our CODM and MPLXT businesses prior to the dates they were acquired by MPLX LP.thus are not reported in our disclosures.
The tables below present information about revenues and other income, from operations andSegment Adjusted EBITDA, capital expenditures and investments in unconsolidated affiliates for our reportable segments:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
L&S | | | | | | | |
Service revenue | $ | 1,130 | | | $ | 1,038 | | | $ | 3,223 | | | $ | 3,031 | |
Rental income | 216 | | | 210 | | | 638 | | | 593 | |
Product related revenue | 6 | | | 4 | | | 14 | | | 15 | |
Sales-type lease revenue | 129 | | | 118 | | | 379 | | | 343 | |
Income from equity method investments | 95 | | | 72 | | | 248 | | | 183 | |
Other income | 15 | | | 8 | | | 47 | | | 42 | |
Total segment revenues and other income(1) | 1,591 | | | 1,450 | | | 4,549 | | | 4,207 | |
Segment Adjusted EBITDA(2) | 1,091 | | | 969 | | | 3,139 | | | 2,839 | |
Capital expenditures | 73 | | | 80 | | | 251 | | | 238 | |
Investments in unconsolidated affiliates | 7 | | | 12 | | | 23 | | | 90 | |
G&P | | | | | | | |
Service revenue | 549 | | | 537 | | | 1,620 | | | 1,528 | |
Rental income | 52 | | | 66 | | | 155 | | | 239 | |
Product related revenue | 598 | | | 742 | | | 1,629 | | | 2,263 | |
Sales-type lease revenue | 34 | | | 28 | | | 101 | | | 28 | |
Income from equity method investments | 64 | | | 53 | | | 190 | | | 152 | |
Other income(3) | 24 | | | 525 | | | 71 | | | 534 | |
Total segment revenues and other income(1) | 1,321 | | | 1,951 | | | 3,766 | | | 4,744 | |
Segment Adjusted EBITDA(2) | 505 | | | 502 | | | 1,507 | | | 1,482 | |
Capital expenditures | 151 | | | 146 | | | 417 | | | 336 | |
Investments in unconsolidated affiliates | $ | 6 | | | $ | 30 | | | $ | 67 | | | $ | 108 | |
(1) Within the total segment revenues and other income amounts presented above, third party revenues for the
reported segments:L&S segment were $207 million and $564 million for the three and nine months ended September 30, 2023, respectively, and $175 million and $468 million for the three and nine months ended September 30, 2022, respectively. Third party revenues for the G&P segment were $1,248 million and $3,553 million for the three and nine months ended September 30, 2023, respectively, and $1,885 million and $4,551 million for the three and nine months ended September 30, 2022, respectively. |
| | | | | | | | | | | |
| Three Months Ended September 30, 2017 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Segment revenues | $ | 378 |
| | $ | 669 |
| | $ | 1,047 |
|
Segment other income | 11 |
| | 1 |
| | 12 |
|
Total segment revenues and other income | 389 |
| | 670 |
| | 1,059 |
|
Costs and expenses: | | | | | |
Segment cost of revenues | 176 |
| | 276 |
| | 452 |
|
Segment operating income before portion attributable to noncontrolling interests and Predecessor | 213 |
| | 394 |
| | 607 |
|
Segment portion attributable to noncontrolling interests and Predecessor | — |
| | 45 |
| | 45 |
|
Segment operating income attributable to MPLX LP | $ | 213 |
| | $ | 349 |
| | $ | 562 |
|
(2) See below for the reconciliation from Segment Adjusted EBITDA to Net income.
(3) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.
|
| | | | | | | | | | | |
| Three Months Ended September 30, 2016 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Segment revenues | $ | 339 |
| | $ | 567 |
| | $ | 906 |
|
Segment other income | 12 |
| | 1 |
| | 13 |
|
Total segment revenues and other income | 351 |
| | 568 |
| | 919 |
|
Costs and expenses: | | | | | |
Segment cost of revenues | 153 |
| | 239 |
| | 392 |
|
Segment operating income before portion attributable to noncontrolling interests and Predecessor | 198 |
| | 329 |
| | 527 |
|
Segment portion attributable to noncontrolling interests and Predecessor | 74 |
| | 36 |
| | 110 |
|
Segment operating income attributable to MPLX LP | $ | 124 |
| | $ | 293 |
| | $ | 417 |
|
|
| | | | | | | | | | | |
| Nine Months Ended September 30, 2017 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Segment revenues | $ | 1,095 |
| | $ | 1,869 |
| | $ | 2,964 |
|
Segment other income | 35 |
| | 2 |
| | 37 |
|
Total segment revenues and other income | 1,130 |
| | 1,871 |
| | 3,001 |
|
Costs and expenses: | | | | |
|
Segment cost of revenues | 500 |
| | 781 |
| | 1,281 |
|
Segment operating income before portion attributable to noncontrolling interests and Predecessor | 630 |
| | 1,090 |
| | 1,720 |
|
Segment portion attributable to noncontrolling interests and Predecessor | 53 |
| | 119 |
| | 172 |
|
Segment operating income attributable to MPLX LP | $ | 577 |
| | $ | 971 |
| | $ | 1,548 |
|
|
| | | | | | | | | | | |
| Nine Months Ended September 30, 2016 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Segment revenues | $ | 901 |
| | $ | 1,595 |
| | $ | 2,496 |
|
Segment other income | 42 |
| | 1 |
| | 43 |
|
Total segment revenues and other income | 943 |
| | 1,596 |
| | 2,539 |
|
Costs and expenses: | | | | |
|
Segment cost of revenues | 392 |
| | 662 |
| | 1,054 |
|
Segment operating income before portion attributable to noncontrolling interests and Predecessor | 551 |
| | 934 |
| | 1,485 |
|
Segment portion attributable to noncontrolling interests and Predecessor | 216 |
| | 113 |
| | 329 |
|
Segment operating income attributable to MPLX LP | $ | 335 |
| | $ | 821 |
| | $ | 1,156 |
|
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Reconciliation to Income from operations: | | | | | | | |
L&S segment operating income attributable to MPLX LP | $ | 213 |
| | $ | 124 |
| | $ | 577 |
| | $ | 335 |
|
G&P segment operating income attributable to MPLX LP | 349 |
| | 293 |
| | 971 |
| | 821 |
|
Segment operating income attributable to MPLX LP | 562 |
| | 417 |
| | 1,548 |
| | 1,156 |
|
Segment portion attributable to unconsolidated affiliates | (47 | ) | | (41 | ) | | (125 | ) | | (130 | ) |
Segment portion attributable to Predecessor | — |
| | 74 |
| | 53 |
| | 216 |
|
Income (loss) from equity method investments | 23 |
| | 6 |
| | 29 |
| | (72 | ) |
Other income - related parties | 13 |
| | 11 |
| | 38 |
| | 29 |
|
Unrealized derivative (losses) gains(1) | (17 | ) | | (2 | ) | | 2 |
| | (23 | ) |
Depreciation and amortization | (164 | ) | | (151 | ) | | (515 | ) | | (438 | ) |
Impairment expense | — |
| | — |
| | — |
| | (130 | ) |
General and administrative expenses | (59 | ) | | (56 | ) | | (174 | ) | | (172 | ) |
Income from operations | $ | 311 |
| | $ | 258 |
| | $ | 856 |
| | $ | 436 |
|
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Reconciliation to Total revenues and other income: | | | | | | | |
Total segment revenues and other income | $ | 1,059 |
| | $ | 919 |
| | $ | 3,001 |
| | $ | 2,539 |
|
Revenue adjustment from unconsolidated affiliates | (107 | ) | | (100 | ) | | (287 | ) | | (303 | ) |
Income (loss) from equity method investments | 23 |
| | 6 |
| | 29 |
| | (72 | ) |
Other income - related parties | 13 |
| | 11 |
| | 38 |
| | 29 |
|
Unrealized derivative (losses) gains related to product sales(1) | (8 | ) | | 2 |
| | 1 |
| | (12 | ) |
Total revenues and other income | $ | 980 |
| | $ | 838 |
| | $ | 2,782 |
| | $ | 2,181 |
|
| |
(1) | The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded. |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Reconciliation to Net income attributable to noncontrolling interests and Predecessor: | | | | | | | |
Segment portion attributable to noncontrolling interests and Predecessor | $ | 45 |
| | $ | 110 |
| | $ | 172 |
| | $ | 329 |
|
Portion of noncontrolling interests and Predecessor related to items below segment income from operations | (21 | ) | | (39 | ) | | (84 | ) | | (157 | ) |
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates | (23 | ) | | (18 | ) | | (49 | ) | | (20 | ) |
Net income attributable to noncontrolling interests and Predecessor | $ | 1 |
| | $ | 53 |
| | $ | 39 |
| | $ | 152 |
|
The following table reconciles segment capital expendituresbelow provides a reconciliation of Segment Adjusted EBITDA for reportable segments to total capital expenditures:Net income.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
Reconciliation to Net income: | | | | | | | |
L&S Segment Adjusted EBITDA | $ | 1,091 | | | $ | 969 | | | $ | 3,139 | | | $ | 2,839 | |
G&P Segment Adjusted EBITDA | 505 | | | 502 | | | 1,507 | | | 1,482 | |
Total reportable segments | 1,596 | | | 1,471 | | | 4,646 | | | 4,321 | |
Depreciation and amortization(1) | (301) | | | (302) | | | (907) | | | (925) | |
Gain on sales-type leases | — | | | 509 | | | — | | | 509 | |
Interest and other financial costs | (225) | | | (236) | | | (701) | | | (691) | |
Income from equity method investments | 159 | | | 125 | | | 438 | | | 335 | |
Distributions/adjustments related to equity method investments | (208) | | | (166) | | | (551) | | | (450) | |
Adjusted EBITDA attributable to noncontrolling interests | 11 | | | 10 | | | 31 | | | 29 | |
Garyville incident response costs(2) | (63) | | | — | | | (63) | | | — | |
Other(3) | (41) | | | 26 | | | (71) | | | 26 | |
Net income | $ | 928 | | | $ | 1,437 | | | $ | 2,822 | | | $ | 3,154 | |
(1) Depreciation and amortization attributable to L&S was $130 million and $399 million for the three and nine months ended September 30, 2023, respectively, and $128 million and $387 million for the three and nine months ended September 30, 2022, respectively. Depreciation and amortization attributable to G&P was $171 million and $508 million for the three and nine months ended September 30, 2023, respectively, and $174 million and $538 million for the three and nine months ended September 30, 2022, respectively.
(2) In August 2023, a naphtha release and resulting fire occurred at our Garyville Tank Farm resulting in the loss of four storage tanks with a combined shell capacity of 894 thousand barrels. We incurred $63 million of incident response costs during the three and nine months ended September 30, 2023.
(3) Includes unrealized derivative gain/(loss), non-cash equity-based compensation, provision for income taxes, and other miscellaneous items.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
L&S segment capital expenditures | $ | 120 |
| | $ | 188 |
| | $ | 353 |
| | $ | 369 |
|
G&P segment capital expenditures | 333 |
| | 183 |
| | 957 |
| | 668 |
|
Total segment capital expenditures | 453 |
| | 371 |
| | 1,310 |
| | 1,037 |
|
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment | 101 |
| | 34 |
| | 306 |
| | 94 |
|
Total capital expenditures | $ | 352 |
| | $ | 337 |
| | $ | 1,004 |
| | $ | 943 |
|
Total assets by reportable segment were:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
Cash and cash equivalents | $ | 3 |
| | $ | 234 |
|
L&S | 4,520 |
| | 2,978 |
|
G&P | 14,715 |
| | 14,297 |
|
Total assets | $ | 19,238 |
| | $ | 17,509 |
|
10. Inventories
Inventories consist of the following:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
NGLs | $ | 3 |
| | $ | 2 |
|
Line fill | 9 |
| | 9 |
|
Spare parts, materials and supplies | 52 |
| | 44 |
|
Total inventories | $ | 64 |
| | $ | 55 |
|
11.8. Property, Plant and Equipment
Property, plant and equipment with associated accumulated depreciation is shown below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | September 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 | | | $ | 12,633 | | | $ | 3,919 | | | $ | 8,714 | | | $ | 12,416 | | | $ | 3,554 | | | $ | 8,862 | |
G&P | | | 13,844 | | | 3,938 | | | 9,906 | | | 13,495 | | | 3,509 | | | 9,986 | |
Total | | | $ | 26,477 | | | $ | 7,857 | | | $ | 18,620 | | | $ | 25,911 | | | $ | 7,063 | | | $ | 18,848 | |
We capitalize interest as part of the cost of major projects during the construction period. Capitalized interest totaled $4 million and $11 million for the three and nine months ended September 30, 2023, respectively, and $2 million and $7 million for the three and nine months ended September 30, 2022, respectively.
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
Natural gas gathering and NGL transportation pipelines and facilities | $ | 5,101 |
| | $ | 4,748 |
|
Processing, fractionation and storage facilities(1) | 3,753 |
| | 3,547 |
|
Pipelines and related assets | 2,181 |
| | 1,799 |
|
Barges and towing vessels | 484 |
| | 479 |
|
Terminals and related assets(1) | 794 |
| | 759 |
|
Land, building, office equipment and other | 755 |
| | 757 |
|
Construction-in-progress | 986 |
| | 1,013 |
|
Total | 14,054 |
| | 13,102 |
|
Less accumulated depreciation | 2,132 |
| | 1,694 |
|
Property, plant and equipment, net | $ | 11,922 |
| | $ | 11,408 |
|
| |
(1) | Certain prior period amounts have been updated to conform to current period presentation. |
12.9. Fair Value Measurements
Fair Values – Recurring
Fair value measurements and disclosures relate primarily toThe following table presents the Partnership’s derivative positions as discussed in Note 13. Money market funds, which are included in Cash and cash equivalentsimpact on the Consolidated Balance Sheets are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. Level 2 instruments include crude oil and natural gas swap contracts. Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The following table presents theMPLX’s financial instruments carried at fair value classified by the valuation hierarchy:
|
| | | | | | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 |
(In millions) | Assets | | Liabilities | | Assets | | Liabilities |
Significant other observable inputs (Level 2) | | | | | | | |
Commodity contracts | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Significant unobservable inputs (Level 3) | | | | | | | |
Commodity contracts | — |
| | (5 | ) | | — |
| | (6 | ) |
Embedded derivatives in commodity contracts | — |
| | (52 | ) | | — |
| | (54 | ) |
Total carrying value in Consolidated Balance Sheets | $ | — |
| | $ | (57 | ) | | $ | — |
| | $ | (60 | ) |
The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instrumentson a recurring basis as of September 30, 2017. The market approach is used for valuation of all instruments.2023 and December 31, 2022 by fair value hierarchy level.
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2023 | | December 31, 2022 |
(In millions) | Asset | | Liability | | Asset | | Liability |
Commodity contracts (Level 2) | | | | | | | |
Other current assets / Other current liabilities | $ | 2 | | | $ | — | | | $ | — | | | $ | — | |
Embedded derivatives in commodity contracts (Level 3) | | | | | | | |
Other current assets / Other current liabilities | — | | | 10 | | | — | | | 10 | |
Other noncurrent assets / Other long-term liabilities | — | | | 50 | | | — | | | 51 | |
Total carrying value in Consolidated Balance Sheets | $ | 2 | | | $ | 60 | | | $ | — | | | $ | 61 | |
|
| | | | | | | | |
Level 3 Instrument | | Balance Sheet Classification | | Unobservable Inputs | | Value Range | | Time Period |
Commodity contracts | | Liabilities | | Forward ethane prices (per Gal)(1)
| | $0.27 - $0.28 | | Oct. 17 - Dec. 17 |
| | | | Forward propane prices (per Gal)(1)
| | $0.68 - $0.91 | | Oct. 17 - Dec. 18 |
| | | | Forward isobutane prices (per Gal)(1)
| | $0.82 - $1.06 | | Oct. 17 - Dec. 18 |
| | | | Forward normal butane prices (per Gal)(1)
| | $0.76 - $1.03 | | Oct. 17 - Dec. 18 |
| | | | Forward natural gasoline prices (per Gal)(1)
| | $1.18 - $1.22 | | Oct. 17 - Dec. 18 |
| | | | | | | | |
Embedded derivatives in commodity contracts | | Assets | | ERCOT Pricing (per MegaWatt Hour) | | $24.19 - $26.05 | | Oct. 17 - Dec. 17 |
| | Liabilities | | Forward propane prices (per Gal)(1)
| | $0.61 - $0.91 | | Oct. 17 - Dec. 22 |
| | | | Forward isobutane prices (per Gal)(1)
| | $0.75 - $1.06 | | Oct. 17 - Dec. 22 |
| | | | Forward normal butane prices (per Gal)(1)
| | $0.69 - $1.03 | | Oct. 17 - Dec. 22 |
| | | | Forward natural gasoline prices (per Gal)(1)
| | $1.15 - $1.22 | | Oct. 17 - Dec. 22 |
| | | | Forward natural gas prices (per MMBtu)(2)
| | $2.30 - $3.11 | | Oct. 17 - Dec. 22 |
| | | | Probability of renewal(3)
| | 50.0% | | |
| | | | Probability of renewal for second 5-yr term(3)
| | 75.0% | | |
| |
(1) | NGL prices used in the valuations decrease over time. |
| |
(2) | Natural gas prices used in the valuations decrease over time. |
| |
(3) | The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future |
business strategy,Level 2 instruments include over-the-counter fixed swaps to mitigate the future commodity price environment, and the future competitive environment for midstream servicesrisk from our sales of propane. The swap valuations are based on observable inputs in the Southern Appalachian region, management determined thatform 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 50natural 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 $0.61 to $1.66 per gallon with a weighted average of $0.79 per gallon and (2) a 100 percent probability of renewal for the first five-yearfive-year renewal term of the gas purchase commitment and 75 percent for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032.
Fair Value Sensitivity Related to Unobservable Inputs
Commodity contracts (assets and liabilities) – For the Partnership’s commodity contracts, increases in forward NGL prices result in a decreaserelated keep-whole processing agreement. Increases or decreases in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another.
Embedded derivatives in commodity contracts – The Partnership has two embedded derivatives in commodity contracts, as follows:
A single embedded derivative liability comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of contract renewal (the “Natural Gas Embedded Derivative”), as discussed further in Note 13. Increases (decreases) in the fracfractionation spread result in an increase (decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.
An embedded derivative related to utilities costs discussed further in Note 13. Increases in the forward Electric Reliability Council of Texas (“ERCOT”) prices result in aor decrease in the fair value of the embedded derivative liability.liability, respectively.
Level 3 Valuation Process
The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts, except for the Natural Gas Embedded Derivative. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and are reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service.
Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 13. Included in the valuation of the Natural Gas Embedded Derivative are assumptions about the forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. The Risk Department must develop forward price curves for NGLs and natural gas through the initial contract term (October 2017 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of:
The estimated favorability of the contracts to the producer customer as compared to other options that would be available to them at the time and in the relative geographic area of their producing assets;
Extrapolated pricing curves, using a weighted average probability method that is based on historical frac spreads, which impact the calculation of favorability; and
The producer customer’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts.
Changes in Level 3 Fair Value Measurements
The tables below includefollowing table is a rollforwardreconciliation of the balance sheet amountsnet beginning and ending balances recorded for the three and nine months ended September 30, 2017 and 2016, respectively (including the change in fair value), for assets andnet liabilities classified by the Partnership withinas Level 3 ofin the valuationfair value hierarchy.
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
| | | | | | | |
Beginning balance | $ | (53) | | | $ | (92) | | | $ | (61) | | | $ | (108) | |
Unrealized and realized (loss)/gain included in Net Income(1) | (10) | | | 44 | | | (7) | | | 52 | |
Settlements | 3 | | | 2 | | | 8 | | | 10 | |
| | | | | | | |
Ending balance | $ | (60) | | | $ | (46) | | | $ | (60) | | | $ | (46) | |
| | | | | | | |
The amount of total (loss)/gain for the period included in earnings attributable to the change in unrealized gain relating to liabilities still held at end of period | $ | (9) | | | $ | 42 | | | $ | (6) | | | $ | 50 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2017 | | Nine Months Ended September 30, 2017 |
(In millions) | Commodity Derivative Contracts (net) | | Embedded Derivatives in Commodity Contracts (net) | | Commodity Derivative Contracts (net) | | Embedded Derivatives in Commodity Contracts (net) |
Fair value at beginning of period | $ | 2 |
| | $ | (43 | ) | | $ | (6 | ) | | $ | (54 | ) |
Total losses (realized and unrealized) included in earnings(1) | (10 | ) | | (12 | ) | | (3 | ) | | (4 | ) |
Settlements | 3 |
| | 3 |
| | 4 |
| | 6 |
|
Fair value at end of period | $ | (5 | ) | | $ | (52 | ) | | $ | (5 | ) | | $ | (52 | ) |
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period | $ | (7 | ) | | $ | (10 | ) | | $ | (4 | ) | | $ | (4 | ) |
(1) (Loss)/gain on derivatives embedded in commodity contracts are recorded in Purchased product costs in the Consolidated Statements of Income.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2016 | | Nine Months Ended September 30, 2016 |
(In millions) | Commodity Derivative Contracts (net) | | Embedded Derivatives in Commodity Contracts (net) | | Commodity Derivative Contracts (net) | | Embedded Derivatives in Commodity Contracts (net) |
Fair value at beginning of period | $ | (4 | ) | | $ | (40 | ) | | $ | 7 |
| | $ | (32 | ) |
Total gains (losses) (realized and unrealized) included in earnings(1) | 2 |
| | (6 | ) | | (5 | ) | | (17 | ) |
Settlements | (1 | ) | | 2 |
| | (6 | ) | | 5 |
|
Netting adjustment(2) | — |
| | — |
| | 1 |
| | — |
|
Fair value at end of period | $ | (3 | ) | | $ | (44 | ) | | $ | (3 | ) | | $ | (44 | ) |
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period | $ | — |
| | $ | (4 | ) | | $ | (4 | ) | | $ | (15 | ) |
| |
(1) | Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs and Cost of revenues.
|
| |
(2) | Certain derivative positions are subject to master netting agreements; therefore, the Partnership has elected to offset derivative assets and liabilities where legally permissible. The Partnership may hold positions with certain counterparties, which for GAAP purposes are classified within different levels of the fair value hierarchy and may be legally permissible to offset. This adjustment represents the total impact of offsetting Level 2 positions with Level 3 positions as of September 30, 2016. |
Fair Values – Reported
The Partnership’s primaryWe believe the carrying value of our other financial instruments, areincluding cash and cash equivalents, receivables, receivables from related parties, lease receivables, lease receivables from related parties, accounts payable, and payables to related parties, and long-term debt. The Partnership’sapproximate fair value. MPLX’s fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) MPC’s investment-grade credit rating, and (3) the historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. The Partnership believes the carrying values of its current assets and liabilities approximate fair value. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 13)10).
The fair value of the Partnership’s long-termMPLX’s debt is estimated based on prices from recent market non-binding indicative quotes. Thetrade activity and is categorized in Level 3 of the fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt and SMR liability fair values are considered Level 3 measurements.hierarchy. The following table summarizes the fair value and carrying value of the long-termour third-party debt, excluding capitalfinance leases and SMR liability:unamortized debt issuance costs:
|
| | | | | | | | | | | | | | | |
| September 30, 2017 | | December 31, 2016 |
(In millions) | Fair Value | | Carrying Value | | Fair Value | | Carrying Value |
Long-term debt | $ | 7,619 |
| | $ | 6,869 |
| | $ | 4,953 |
| | $ | 4,422 |
|
SMR liability | 106 |
| | 92 |
| | 108 |
| | 96 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2023 | | December 31, 2022 |
(In millions) | Fair Value | | Carrying Value | | Fair Value | | Carrying Value |
Outstanding debt(1) | $ | 17,922 | | | $ | 20,536 | | | $ | 18,095 | | | $ | 19,905 | |
13. Derivative Financial Instruments
Commodity Derivatives
NGL and natural gas prices(1) Any amounts outstanding under the MPC Loan Agreement are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. A portion of the Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital plans, the Partnership executes a strategy governed by its risk management policy. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changesnot included in the prices of natural gas and NGLs. Derivative contracts utilized are swaps traded ontable above, as the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.
To mitigate its cash flow exposure to fluctuationscarrying value approximates fair value. This balance is reflected in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on its current volume forecasts, the majority of its derivative positions used to manage the future commodity price exposure are expected to be direct product NGL derivative contracts.
To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.
As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2018. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.
Management conducts a standard credit review on counterparties to derivative contracts and has provided the counterparties with a guaranty as credit support for its obligations. A separate agreement with certain counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.
The Partnership records derivative contracts at fair valueCurrent liabilities - related parties in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation (except for electricity and certain other qualifying contracts,Sheets.
10. Derivatives
As of September 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 (gallons) | | Short | | 16,827,000 | |
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 whichone five-year term through December 2032. For accounting purposes, the normal purchasesnatural gas purchase commitment and normal sales designation hasthe term extending option have been elected).aggregated into a single compound embedded derivative. The Partnership’s accountingprobability of the customer exercising its option is determined based on assumptions about the customer’s potential business strategy decision points that may cause volatilityexist 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 asIncome. For further information regarding the Partnership recognizes all unrealized gainsfair value measurement of derivative instruments, see Note 9. As of September 30, 2023 and losses fromDecember 31, 2022, the changes inestimated fair value of derivativesthis contract was a liability of $60 million and $61 million, respectively.
Certain derivative positions are subject to master netting agreements; therefore, MPLX has elected to offset derivative assets and liabilities that are legally permissible to be offset. As of September 30, 2023 and December 31, 2022, there were no derivative assets or liabilities that were offset in current earnings. The Partnership makesthe 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.
Volume of Commodity Derivative Activity
As of September 30, 2017, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs and purchases of natural gas:
|
| | | | | |
Derivative contracts not designated as hedging instruments | | Financial Position | | Notional Quantity (net) |
Crude Oil (bbl) | | Short | | 18,400 |
|
Natural Gas (MMBtu) | | Long | | 1,096,539 |
|
NGLs (gal) | | Short | | 33,387,904 |
|
Embedded Derivatives in Commodity Contracts
The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the Partnership executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contract. The changes in fair value of this 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. As of September 30, 2017 and December 31, 2016, the estimated fair value of this contract was a liability of $52 million and $54 million, respectively.
The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of Revenues in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.
Financial Statement Impact of Derivative Contracts
There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:
|
| | | | | | | | | | | | | | | | |
(In millions) | | September 30, 2017 | | December 31, 2016 |
Derivative contracts not designated as hedging instruments and their balance sheet location | | Asset | | Liability | | Asset | | Liability |
Commodity contracts(1) | | | | | | | | |
Other current assets / other current liabilities | | $ | — |
| | $ | (15 | ) | | $ | — |
| | $ | (13 | ) |
Other noncurrent assets / deferred credits and other liabilities | | — |
| | (42 | ) | | — |
| | (47 | ) |
Total | | $ | — |
| | $ | (57 | ) | | $ | — |
| | $ | (60 | ) |
| |
(1) | Includes embedded derivatives in commodity contracts as discussed above. |
Certain derivative positions are subject to master netting agreements, therefore the Partnership has elected to offset derivative assets and liabilities that are legally permissible to be offset. The net amounts in the table below equal the balances presented in the Consolidated Balance Sheets:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| September 30, 2017 |
| Assets | | Liabilities |
(In millions) | Gross Amount | | Gross Amounts Offset in the Consolidated Balance Sheets | | Net Amount of Assets in the Consolidated Balance Sheets | | Gross Amount | | Gross Amounts Offset in the Consolidated Balance Sheets | | Net Amount of Liabilities in the Consolidated Balance Sheets |
Current | | | | | | | | | | | |
Commodity contracts | $ | — |
| | $ | — |
| | $ | — |
| | $ | (5 | ) | | $ | — |
| | $ | (5 | ) |
Embedded derivatives in commodity contracts | — |
| | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) |
Total current derivative instruments | — |
| | — |
| | — |
| | (15 | ) | | — |
| | (15 | ) |
Non-current | | | | | | | | | | | |
Commodity contracts | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Embedded derivatives in commodity contracts | — |
| | — |
| | — |
| | (42 | ) | | — |
| | (42 | ) |
Total non-current derivative instruments | — |
| | — |
| | — |
| | (42 | ) | | — |
| | (42 | ) |
Total derivative instruments | $ | — |
| | $ | — |
| | $ | — |
| | $ | (57 | ) | | $ | — |
| | $ | (57 | ) |
In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit).
The impact of the Partnership’sMPLX’s derivative contracts not designated as hedging instruments and the location of gain or (loss)gains and losses recognized in the Consolidated Statements of Income is summarized below:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | 2023 | | 2022 |
Product sales: | | | | | | | |
Realized gain | $ | 3 | | | $ | — | | | $ | 3 | | | $ | — | |
Unrealized (loss)/gain | (8) | | | — | | | 2 | | | — | |
Product sales derivative (loss)/gain | (5) | | | — | | | 5 | | | — | |
Purchased product costs: | | | | | | | |
Realized loss | (3) | | | (2) | | | (8) | | | (10) | |
Unrealized (loss)/gain | (7) | | | 46 | | | 1 | | | 62 | |
Purchased produce cost derivative (loss)/gain | (10) | | | 44 | | | (7) | | | 52 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total derivative (loss)/gain included in Net income | $ | (15) | | | $ | 44 | | | $ | (2) | | | $ | 52 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Product sales | | | | | | | |
Realized (loss) gain | $ | (2 | ) | | $ | — |
| | $ | (3 | ) | | $ | 6 |
|
Unrealized (loss) gain | (8 | ) | | 2 |
| | 1 |
| | (12 | ) |
Total derivative (loss) gain related to product sales | (10 | ) | | 2 |
| | (2 | ) | | (6 | ) |
Purchased product costs | | | | | | | |
Realized loss(1) | (2 | ) | | (1 | ) | | (6 | ) | | (4 | ) |
Unrealized (loss) gain | (9 | ) | | (3 | ) | | 1 |
| | (12 | ) |
Total derivative loss related to purchased product costs | (11 | ) | | (4 | ) | | (5 | ) | | (16 | ) |
Cost of revenues | | | | | | | |
Realized loss(1) | — |
| | — |
| | — |
| | (2 | ) |
Unrealized (loss) gain | — |
| | (1 | ) | | — |
| | 1 |
|
Total derivative loss related to cost of revenues | — |
| | (1 | ) | | — |
| | (1 | ) |
Total derivative losses | $ | (21 | ) | | $ | (3 | ) | | $ | (7 | ) | | $ | (23 | ) |
| |
(1) | Certain prior period amounts have been updated to conform to current period presentation. |
14.11. Debt
The Partnership’sMPLX’s outstanding borrowings consistedconsist of the following: |
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(In millions) | September 30, 2017 | | December 31, 2016 |
MPLX LP: | | | |
Bank revolving credit facility due 2022 | $ | 420 |
| | $ | — |
|
Term loan facility due 2019 | — |
| | 250 |
|
5.500% senior notes due February 2023 | 710 |
| | 710 |
|
4.500% senior notes due July 2023 | 989 |
| | 989 |
|
4.875% senior notes due December 2024 | 1,149 |
| | 1,149 |
|
4.000% senior notes due February 2025 | 500 |
| | 500 |
|
4.875% senior notes due June 2025 | 1,189 |
| | 1,189 |
|
4.125% senior notes due March 2027 | 1,250 |
| | — |
|
5.200% senior notes due March 2047 | 1,000 |
| | — |
|
Consolidated subsidiaries: | | | |
MarkWest - 4.500% - 5.500% senior notes, due 2023-2025 | 63 |
| | 63 |
|
MPL - capital lease obligations due 2020 | 7 |
| | 8 |
|
Total | 7,277 |
| | 4,858 |
|
Unamortized debt issuance costs | (27 | ) | | (7 | ) |
Unamortized discount | (401 | ) | | (428 | ) |
Amounts due within one year | (1 | ) | | (1 | ) |
Total long-term debt due after one year | $ | 6,848 |
| | $ | 4,422 |
|
| | | | | | | | | | | |
(In millions) | September 30, 2023 | | December 31, 2022 |
MPLX LP: | | | |
| | | |
MPLX Credit Agreement | $ | — | | | $ | — | |
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Fixed rate senior notes | 20,657 | | | 20,046 | |
Consolidated subsidiaries: | | | |
MarkWest | 12 | | | 23 | |
ANDX | 31 | | | 31 | |
| | | |
Finance lease obligations | 7 | | | 8 | |
Total | 20,707 | | | 20,108 | |
Unamortized debt issuance costs | (125) | | | (117) | |
Unamortized discount | (164) | | | (195) | |
Amounts due within one year | (1) | | | (988) | |
Total long-term debt due after one year | $ | 20,417 | | | $ | 18,808 | |
Credit AgreementsAgreement
On July 21, 2017, the Partnership entered into a syndicatedMPLX’s credit agreement to replace its previously outstanding $2.0(the “MPLX Credit Agreement”) matures in July 2027 and, among other things, provides for a $2 billion five-year bankunsecured revolving credit facility with a $2.25and 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 five-year bank revolving credit facility that expires in July 2022 (the “MPLXborrowing capacity. Borrowings under the MPLX Credit Agreement 2022”). The financial covenants andbear interest, at MPLX’s election, at either the interest rate terms containedAdjusted Term SOFR or the Alternate Base Rate, both as defined in the new credit agreement are substantiallyMPLX Credit Agreement, plus an applicable margin.
There was no activity on the same as those contained in the previous bank revolving credit facility. DuringMPLX Credit Agreement during the nine months ended September 30, 2017, the Partnership had no borrowings under the previous bank revolving credit facility. During the nine months ended September 30, 2017, the Partnership borrowed$420 million under the MPLX Credit Agreement 2022, at an average interest rate of 2.702 percent. At September 30, 2017, the Partnership had $420 million outstanding borrowings and $3 million letters of credit outstanding under the new facility, resulting in total availability of $1.827 billion, or 81.2 percent of the borrowing capacity.2023.
The $250 million term loan facility was drawn in full on November 20, 2014. On July 19, 2017, MPLX LP prepaid the entire outstanding principal of this loan facility with cash on hand. The borrowings under this facility between January 1, 2017 and July 19, 2017 were at an average interest rate of 2.407 percent.
Fixed Rate Senior Notes
On February 10, 2017, the Partnership completed a public offering of $2.25 billion aggregate principal amount of unsecuredMPLX’s senior notes, consistingincluding those issued by consolidated subsidiaries, consist of (i) $1.25 billion aggregate principal amountvarious series of 4.125 percent senior notes due in March 2027maturing between 2024 and (ii) $1.0 billion aggregate principal amount of 5.2002058 with interest rates ranging from 1.750 percent senior notes due in March 2047 (collectively, the “New Senior Notes”). The net proceeds from the New Senior Notes totaled approximately $2.22 billion, after deducting underwriting discounts, and were used for general partnership purposes and capital expenditures.to 5.650 percent. Interest on each series of the notes is payable semi-annually in arrears on March 1various dates depending on the series of the notes.
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 September 1,$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, 2017.2023. 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, net.
12. Revenue
15.
Disaggregation of Revenue
The following tables represent a disaggregation of revenue for each reportable segment for the three and nine months ended September 30, 2023 and September 30, 2022:
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2023 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Service revenue | $ | 97 | | | $ | 544 | | | $ | 641 | |
Service revenue - related parties | 1,033 | | | 5 | | | 1,038 | |
Service revenue - product related | — | | | 75 | | | 75 | |
Product sales | 2 | | | 476 | | | 478 | |
Product sales - related parties | 4 | | | 47 | | | 51 | |
Total revenues from contracts with customers | $ | 1,136 | | | $ | 1,147 | | | 2,283 | |
Non-ASC 606 revenue(1) | | | | | 629 | |
Total revenues and other income | | | | | $ | 2,912 | |
| | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, 2022 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Service revenue | $ | 94 | | | $ | 533 | | | $ | 627 | |
Service revenue - related parties | 944 | | | 4 | | | 948 | |
Service revenue - product related | — | | | 83 | | | 83 | |
Product sales | 2 | | | 615 | | | 617 | |
Product sales - related parties | 2 | | | 44 | | | 46 | |
Total revenues from contracts with customers | $ | 1,042 | | | $ | 1,279 | | | 2,321 | |
Non-ASC 606 revenue(1) | | | | | 1,080 | |
Total revenues and other income | | | | | $ | 3,401 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2023 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Service revenue | $ | 272 | | | $ | 1,609 | | | $ | 1,881 | |
Service revenue - related parties | 2,951 | | | 11 | | | 2,962 | |
Service revenue - product related | — | | | 214 | | | 214 | |
Product sales | 4 | | | 1,270 | | | 1,274 | |
Product sales - related parties | 10 | | | 145 | | | 155 | |
Total revenues from contracts with customers | $ | 3,237 | | | $ | 3,249 | | | 6,486 | |
Non-ASC 606 revenue(1) | | | | | 1,829 | |
Total revenues and other income | | | | | $ | 8,315 | |
| | | | | | | | | | | | | | | | | |
| Nine Months Ended September 30, 2022 |
(In millions) | L&S | | G&P | | Total |
Revenues and other income: | | | | | |
Service revenue | $ | 243 | | | $ | 1,515 | | | $ | 1,758 | |
Service revenue - related parties | 2,788 | | | 13 | | | 2,801 | |
Service revenue - product related | — | | | 324 | | | 324 | |
Product sales | 5 | | | 1,807 | | | 1,812 | |
Product sales - related parties | 10 | | | 132 | | | 142 | |
Total revenues from contracts with customers | $ | 3,046 | | | $ | 3,791 | | | 6,837 | |
Non-ASC 606 revenue(1) | | | | | 2,114 | |
Total revenues and other income | | | | | $ | 8,951 | |
(1) Non-ASC 606 Revenue includes rental income, sales-type lease revenue, income from equity method investments, 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 nine-month periods ended September 30, 2023 and September 30, 2022:
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(In millions) | Balance at December 31, 2022 | | Additions/ (Deletions) | | Revenue Recognized(1) | | Balance at September 30, 2023 |
Contract assets | $ | 21 | | | $ | (19) | | | $ | — | | | $ | 2 | |
Long-term contract assets | 1 | | | — | | | — | | | 1 | |
Deferred revenue | 57 | | | 24 | | | (31) | | | 50 | |
Deferred revenue - related parties | 63 | | | 63 | | | (72) | | | 54 | |
Long-term deferred revenue | 216 | | | 76 | | | — | | | 292 | |
Long-term deferred revenue - related parties | 25 | | | 5 | | | — | | | 30 | |
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Long-term contract liabilities | $ | 2 | | | $ | (2) | | | $ | — | | | $ | — | |
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(In millions) | Balance at December 31, 2021 | | Additions/ (Deletions) | | Revenue Recognized(1) | | Balance at September 30, 2022 |
Contract assets | $ | 25 | | | $ | (9) | | | $ | — | | | $ | 16 | |
Long-term contract assets | 2 | | | — | | | — | | | 2 | |
Deferred revenue | 56 | | | 40 | | | (33) | | | 63 | |
Deferred revenue - related parties | 60 | | | 79 | | | (83) | | | 56 | |
Long-term deferred revenue | 135 | | | 27 | | | — | | | 162 | |
Long-term deferred revenue - related parties | 31 | | | (5) | | | — | | | 26 | |
Long-term contract liabilities | $ | 5 | | | $ | (1) | | | $ | — | | | $ | 4 | |
(1) No significant revenue was recognized related to past performance obligations in the current periods.
Remaining Performance Obligations
The table below includes estimated revenue expected to be recognized in the future related to performance obligations that are unsatisfied (or partially unsatisfied) as of September 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 | $ | 0.5 | |
2024 | 2.0 | |
2025 | 1.9 | |
2026 | 1.7 | |
2027 | 1.6 | |
Thereafter | 1.0 | |
Total estimated revenue on remaining performance obligations | $ | 8.7 | |
As of September 30, 2023, unsatisfied performance obligations included in the Consolidated Balance Sheets are $426 million and will be recognized as revenue as the obligations are satisfied, which is expected to occur over the next 20 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
| | | | | | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 |
Net cash provided by operating activities included: | | | |
Interest paid (net of amounts capitalized) | $ | 724 | | | $ | 642 | |
Income taxes paid | 4 | | | 2 | |
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Non-cash investing and financing activities: | | | |
Net transfers of property, plant and equipment (to)/from materials and supplies inventories | 8 | | | — | |
Net transfers of property, plant and equipment to lease receivable | $ | 86 | | | $ | 20 | |
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| Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 |
Net cash provided by operating activities included: | | | |
Interest paid (net of amounts capitalized) | $ | 207 |
| | $ | 158 |
|
Non-cash investing and financing activities: | | | |
Net transfers of property, plant and equipment from materials and supplies inventories | $ | 6 |
| | $ | (4 | ) |
Contribution of fixed assets to joint venture(1) | 337 |
| | — |
|
| |
(1) | Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 4. |
The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that diddo not affect cash. The following is the changea reconciliation of additions to property, plant and equipment to total capital expenditures:
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| Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 |
Additions to property, plant and equipment | $ | 662 | | | $ | 535 | |
Increase in capital accruals | 6 | | | 39 | |
| | | |
Total capital expenditures | $ | 668 | | | $ | 574 | |
14. Leases
During the third quarter of 2022, the approved expansion of a gathering and compression system triggered the first assessment of the related third-party agreement under ASC 842. Similarly, an amendment to capital accruals:extend the term of our butane storage service agreement with MPC triggered the first assessment of the related-party agreement under ASC 842. As a result of the assessments during the third quarter of 2022, the leases were reclassified from operating leases to sales-type leases. Accordingly, the underlying property, plant and equipment, net, and associated deferred revenue, if any, were derecognized. The present value of the future lease payments and the unguaranteed residual value of the assets were recorded as a net investment in sales-type lease during the period.
|
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| Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 |
Increase in capital accruals | $ | 55 |
| | $ | — |
|
16. Equity-Based Compensation
Phantom Units – The following is a summary of phantom unit award activity of MPLX LP common units forpresents the nine months ended September 30, 2017:
|
| | | | | | |
| Number of Units | | Weighted Average Fair Value |
Outstanding at December 31, 2016 | 1,173,411 |
| | $ | 33.09 |
|
Granted | 653,721 |
| | 36.36 |
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Settled | (288,584 | ) | | 33.50 |
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Forfeited | (113,107 | ) | | 34.59 |
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Outstanding at September 30, 2017 | 1,425,441 |
| | 34.39 |
|
Performance Units – The Partnership grants performance units under the MPLX LP 2012 Incentive Compensation Plan to certain officersconsolidated financial statement impact of the general partner and certain eligiblesales-type lease modifications discussed above. These transactions, including any related gains recognized in the Consolidated Statements of Income, were non-cash transactions.
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| | | Three Months Ended September 30, 2022 |
(In millions) | | | | | Related Party(1) | | Third Party(2) |
Lease receivables | | | | | $ | 79 | | | $ | 914 | |
Unguaranteed residual assets | | | | | 6 | | | 63 | |
Property, plant and equipment, net | | | | | (42) | | | (745) | |
Deferred revenue | | | | | — | | | 277 | |
Amount recognized on commencement date | | | | | $ | 43 | | | $ | 509 | |
(1) The amount recognized on commencement date was recorded as a Contribution from MPC officers who make significant contributions to its business. These performance units pay out 75 percent in cash and 25 percentthe Consolidated Statements of Equity given the underlying agreements are between entities under common control.
(2) The amount recognized on commencement date was recorded as a gain in MPLX LP common units. The performance units paying outOther income in units are accounted for as equity awards. The performance units granted in 2017 are hybrid awards having a three-year performance periodthe Consolidated Statements of January 1, 2017 through December 31, 2019. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX LP’s DCF during the last twelve months of the performance period, and a market condition based on MPLX LP’s total unitholder return over the entire three-year performance period. The market condition was valued using a Monte Carlo valuation, with the result being combined with the expected payout of the performance condition as of the grant date, resulting in a grant date fair value of $0.90 for the 2017 equity-classified performance units.Income.
The following is a summary of the equity-classified performance unit award activity for the nine months ended September 30, 2017:
|
| | |
| Number of
Units |
Outstanding at December 31, 2016 | 1,799,249 |
|
Granted | 1,407,062 |
|
Settled | (464,500 | ) |
Forfeited | (35,217 | ) |
Outstanding at September 30, 2017 | 2,706,594 |
|
17.15. Commitments and Contingencies
The PartnershipMPLX is the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which the PartnershipMPLX has not recorded an accrueda liability, the PartnershipMPLX is unable to estimate a range of possible losses forloss because the reasons discussed in more detail below.issues involved have not been fully developed through pleadings, discovery or court proceedings. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.
Environmental Matters – The Partnership
MPLX is subject to federal, state and local laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for non-compliance.
At September 30, 2017 and December 31, 2016, accruedAccrued liabilities for remediation totaled $14$23 million at September 30, 2023 and $3$17 million respectively. However, it 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, whichthat may be imposed. At December 31, 2016, there was less than $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering. There were no such receivables at September 30, 2017.
In July 2015, representatives from the EPA and the United States Department of Justice conducted a raid on a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United States District Court for the Western District of Pennsylvania. As part of this initiative, the U.S. Attorney’s Office for the Western District of Pennsylvania proceeded with an investigation of MarkWest Liberty Midstream’s launcher/receiver, pipeline and compressor station operations. In response to the investigation, MarkWest initiated independent studies which demonstrated that there was no risk to worker safety and no threat of public harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings were supported by a subsequent inspection and review by the Occupational Safety and Health Administration. After providing these studies, and other substantial documentation related to MarkWest Liberty Midstream's pipeline and compressor stations, and arranging site visits and conducting several meetings with the government’s representatives, on September 13, 2016, the U.S. Attorney’s Office for the Western District of Pennsylvania rendered a declination decision, dropping its criminal investigation and declining to pursue charges in this matter.
MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement allegations associated with permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the region. In connection with these discussions, MarkWest Liberty Midstream received an initial proposal from the EPA to settle all civil claims associated with this matter for the combination of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream has submitted a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis and were not the subject of regulation and consequently that the settlement proposal is excessive. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.
The PartnershipMPLX is involved in a number of other environmental enforcement matters arising in the ordinary course of business. While the outcome and impact onto MPLX LP cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its consolidated results of operations, financial position or cash flows.
Other Lawsuits – Legal Proceedings
In 2003,July 2020, Tesoro High Plains Pipeline Company, LLC (“THPP”), a subsidiary of MPLX, received a Notification of Trespass Determination from the StateBureau of Illinois broughtIndian 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 actionorder 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 Premcor Refining Group, Inc. (“Premcor”United States of America, the U.S. Department of the Interior and the BIA (together, the “U.S. Government Parties”) and Apex Refining Company (“Apex”) asserting claims for environmental cleanupchallenging the March 2021 order purporting to vacate all previous orders related to THPP’s alleged trespass. On February 8, 2022, the refinery owned by these entitiesU.S. Government Parties filed their answer and counterclaims to THPP’s suit claiming THPP is in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area, including Marathon Pipe Line LLC (“MPL”). These complaints, which have been amended since filing, assert claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6, 2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle all claims against it for a $10 million payment. Premcor has objected to this ruling and is seeking an appeal. There are several third-party defendants in the litigation and MPL has asserted cross-claims in contribution against the various third-party defendants. This litigation is currently pending in the Third Judicial Circuit Court, Madison County,
Illinois. While the ultimate outcome of these litigated matters remains uncertain, neither the likelihood of an unfavorable outcome nor the ultimate liability, if any,continued trespass with respect to this matter can be determined at this timethe pipeline and seeking disgorgement of pipeline profits from June 1, 2013 to present, removal of the Partnership is unablepipeline and remediation. We intend to estimate a reasonably possible loss (or range of losses) for this litigation. Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any damages in this lawsuit.vigorously defend ourselves against these counterclaims.
The PartnershipMPLX 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 the PartnershipMPLX cannot be predicted with certainty, the Partnershipmanagement believes the resolution of these other lawsuits and proceedings will not, individually or collectively, have a material adverse effect on its consolidated financial position, results of operations or cash flows.
Guarantees – Over related to indebtedness of equity method investees
We hold a 9.19 percent indirect interest in Dakota Access, which owns and operates the years,Bakken Pipeline system. In 2020, the PartnershipU.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 Army Corps issued a draft EIS in September 2023 detailing various options for the easement going forward, including denying the easement, approving the easement with additional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has sold various assetsnot selected a preferred alternative, but will make a decision in its final review, after considering input from the public and other agencies. The Army Corps has not provided a definitive date as to when a final decision would be issued.
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 normal courseBakken 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 its business. Certainconstruction of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that requireBakken Pipeline system.
If the Partnership to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are partvacatur of the normal courseeasement results in a temporary shutdown of selling assets. The Partnershipthe pipeline, 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 typically not ableshutdown. MPLX also expects to calculatecontribute its 9.19 percent pro rata share of any costs to remediate any deficiencies to reinstate the easement and/or return the pipeline into operation. If the vacatur of the easement 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 September 30, 2023, our maximum potential amount of futureundiscounted payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.Contingent Equity Contribution Agreement were approximately $170 million.
Contractual Commitments and Contingencies – At September 30, 2017, the Partnership’s contractual commitments to acquire property, plant and equipment totaled $520 million. These commitments at September 30, 2017 were primarily related to plant expansion projects for the Marcellus and Southwest Operations. In addition, from
From time to time and in the ordinary course of business, the PartnershipMPLX and its affiliates provide guarantees of the Partnership’sMPLX’s subsidiaries payment and performance obligations in the G&P segment. Certain natural gas processing and gathering arrangements require the PartnershipMPLX 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 September 30, 2017,2023, management does not believe there are any indications that the PartnershipMPLX 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.
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, 2016, as updated by our Current2022.
Disclosures Regarding Forward-Looking Statements
This Quarterly Report on Form 8-K filed on May 1, 2017.
10-Q, particularly Management’s Discussion and Analysis of Financial Condition and Results of Operations and Quantitative and Qualitative Disclosures about Market Risk, includes various forward-looking statements concerning trendsthat are subject to risks, contingencies or events potentially affecting our business.uncertainties. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,“commitment,” “objective,“could,” “design,” “estimate,” “expect,” “forecast,” “goal,” “guidance,” “intend,” “may,” “objective,” “opportunity,” “outlook,” “plan,” “policy,” “position,” “potential,” “predict,” “priority,” “project,” “potential,“prospective,” “pursue,” “seek,” “should,” “strategy,” “target,” “could,“will,” “may,” “should,” “would,” “will”“would” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions
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 Private Securities Litigation Reform Actsuccess or timing of 1995,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 accompaniedmaterial 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, hostilities in the Middle East, 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 cautionary language identifying important factors, though not necessarily allcompetitors;
•disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;
•the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;
•modifications to financial policies, capital budgets, and earnings and distributions;
•the ability to manage disruptions in credit markets or changes to credit ratings;
•compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;
•adverse results in litigation;
•the 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 factors, whichfuels 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;
•our ability to maintain adequate insurance coverage and recover insurance proceeds to offset losses resulting from accidents or other insurance incidents and unscheduled shutdowns;
•acts of war, terrorism or civil unrest that could cause future outcomesimpair our ability to differ materially from those set forthgather, 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 forward-looking statements. 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 Item 1A. Risk Factorsthe risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2016.2022. We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.
PARTNERSHIP OVERVIEWMPLX Overview
We are a diversified, growth-orientedlarge-cap master limited partnership formed by MPC to own, operate, developin 2012 that owns and acquireoperates midstream energy infrastructure assets. We are engagedand 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, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the transportation, storage and distribution of crude oil, refined products, other hydrocarbon-based products, and refined petroleum products.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.
SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS
Significant Financial and Other Highlights
Significant financial and other highlights for the three months ended September 30, 20172023 and September 30, 2022 are listedshown in the chart below. Refer to the Results of Operations, andthe Liquidity and Capital Resources, and Non-GAAP Financial Information sections for further details.information.
L&S segment operating income attributable to MPLX LP increased approximately $89(1) The 2022 amounts include a $509 million or 72 percent,non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.
(2) Non-GAAP measure. See reconciliations that follow for the three months ended September 30, 2017 comparedmost directly comparable GAAP measures.
Other Highlights
•Returned $799 million and $2,419 million of capital to the same period of 2016 due to $74 million from the inclusion of HST, WHC and MPLXT results after our acquisition as of March 1, 2017and$7 million from the acquisition of the Ozark pipeline.
G&P segment operating income attributable to MPLX LP increased approximately $56 million, or 19 percent, for the three months ended September 30, 2017 compared to the same period of 2016. The G&P segment realized product price increases and volume increases during the third quarter of 2017 primarily due to expansionsunitholders in the Southwest as well as growth at the Sherwood, Majorsville and Bluestone (previously referred to as Keystone) plants. Compared to the third quarter of 2016, processing volumes were up approximately 11 percent, fractionated volumes were up approximately 14 percent and gathering volumes were up approximately 13 percent.
Additional highlights for the three and nine months ended September 30, 2017, including2023, via distributions.
•Announced a look ahead to anticipated growth, are listed below.third quarter 2023 distribution of $0.850 per common unit, representing a 10% increase over the prior quarter’s distribution.
AcquisitionGaryville Tank Farm Incident
In August 2023, a naphtha release and Growth Activities
On September 27, 2017, MPC authorized an offer of MPLX Fuels Distributions LLC and MPLX Refining Logistics LLC to MPLX LP in exchange for cash and limited and general partnership units. MPLX Fuels Distribution LLC is structured to provide a broad range of scheduling and marketing services as MPC’s sole and exclusive agent. MPLX Refining Logistics LLC contains the integrated tank farm assets that support MPC’s refining operations. These essential logistics assets include: approximately 56 million barrels storage capacity (crude, finished products and intermediates)resulting fire occurred at our Garyville Tank Farm (“Garyville Incident”), 619 tanks, 32 rail and truck racks, and 18 docks and gasoline blenders. This offer, which is projected to contribute approximately $1.0 billion of annual EBITDA, is currently under review by the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018. If approved, this acquisition will complete a series of planned acquisitions of assets from MPC that began in early 2017. The combined sum of the three transactions totals an estimated $1.4 billion of annual EBITDA. The stable, fee-based earnings from these acquired assets add both scale and diversification to our portfolio of high-quality midstream assets.
On September 1, 2017, we acquired joint-interest ownerships in certain pipelines and storage facilities from MPC for $420 million in cash and the issuance of $653 million in MPLX LP equity. The acquired ownership interests include a 35 percent ownership interest in Illinois Extension, a 40.7 percent ownership interest in LOOP, a 58.52 percent ownership interest in LOCAP, and a 24.51 percent ownership interest in Explorer. The assets held by these entities include a 1,830-mile refined products pipeline, storage facilities, pump stations, and an offshore deep water oil port located along the Gulf Coast. The infrastructure serves primarily the Midwest and Gulf Coast regions of the United States. There is no income associated with the Joint-Interest Acquisition includedresulting in the Consolidated Statementsloss of Income since the September 1, 2017 acquisition date, as we account for these equity method investments in arrears using the most recently available information.
On March 1, 2017, we acquired certain pipeline,four storage and terminal assets from MPC for $1.5 billion in cash and the issuance of $503 million in MPLX LP equity. As of the acquisition date, the assets consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines, nine butane and propane storage caverns located in Michigantanks with approximately 1.8 million barrels of NGL storage capacity, 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products, along with one leased terminal and partial ownership interest in two terminals. Collectively, the 62 terminals had a combined total shell capacity of approximately 23.6894 thousand barrels. We incurred $63 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States.
On March 1, 2017, we purchased the 433-mile, 22-inch Ozark crude oil pipeline for $219 million. The pipeline is capable of transporting approximately 230 mbpd and expands the footprint of our logistics and storage segment by connecting Cushing, Oklahoma-sourced volumes to our extensive Midwest pipeline network. An expansion project to increase the line's capacity to approximately 345 mbpd is expected to be completed in the second quarter of 2018.
On February 15, 2017, we acquired a 9.1875 percent indirect equity interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the Bakken Pipeline system, for $500 million. The Bakken Pipeline system is currently expected to deliver in excess of 520 mbpd of crude oil from the Bakken/Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. During the third quarter 2017, MPLX LP benefited from the first full quarter of earnings from its indirect interest in the Bakken Pipeline system. Initial cash distributions related to this investment were also receivedincident response costs during the third quarter 2017.
On February 6, 2017, we formed a strategic joint venture with Antero Midstream to process natural gas at the Sherwood Complexthree and fractionate natural gas liquids at the Hopedale Complex. This unique transaction strengthens our long-term relationship with the largest producer in the Appalachian Basin and provides the Partnership with substantial future growth opportunities. As part of this agreement, Antero Midstream released to the joint venture the dedication of approximately 195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. We contributed cash of $20 million, along with $353 million of assets, comprised of real property, equipment and facilities, including three 200 MMcf/d gas processing plants then under construction at the Sherwood Complex. Antero Midstream contributed cash of $154 million. The joint venture commenced operations of the first new facility during the first quarter of 2017, the second new facility during the third quarter of 2017 and expects to commence operations of the third new facility during the first quarter of 2018. Construction of a fourth new facility was announced during the first quarter of 2017 and is expected to commence operations in late 2018. In addition to the four new processing facilities, the joint venture contemplates the development of up to another seven processing facilities to support Antero Resources Corporation, which would be located at both the Sherwood Complex and a new location in West Virginia. At the Hopedale Complex, the largest fractionation facility in the Marcellus and Utica shales, the joint venture will also support the growth of Antero Resources Corporation’s NGL production by investing in 20 mbpd of existing fractionation capacity, with options to invest in future fractionation expansions.
Financing Activities
On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0 billion five-year bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in July 2022. The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstanding principal amount of its $250 million term loan with cash on hand.
On February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount of senior notes (the “New Senior Notes”).
During the nine months ended September 30, 2017,2023. We are pursuing recovery of property damage and incident response costs under the relevant insurance policies, although there can be no assurance as to the amount of recovery, if any.
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 issuedhave increased the fees we charge our customers to reflect higher levels of inflation.
Succession Planning
As previously disclosed, MPC maintains a mandatory retirement policy that, absent a waiver or extension, requires an aggregateexecutive officer to retire from service to the company coincident with, or immediately following, the first of 13,846,998 commons units underthe month after such executive officer reaches age 65 (the "Policy"). Michael J. Hennigan, President and Chief Executive Officer of our ATM Program, generating net proceedsgeneral partner, as well as the President and Chief Executive Officer of approximately $473 million. AsMPC, will reach mandatory retirement on August 1, 2024. Accordingly, the MPC Board of September 30, 2017, $1.7 billionDirectors, with a focus on the long-term strategic direction of common units remain available for issuance through the ATM Program.company, is engaged in appropriate succession planning activities, which are expected to include, among other customary steps, the review of succession candidates, as well as consideration of any waiver or extension of the Policy respecting Mr. Hennigan.
NON-GAAP FINANCIAL INFORMATION
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 DCF.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 the Partnership’sMPLX’s cash distributions.
We define Adjusted EBITDA as net income adjusted forfor: (i) depreciation and amortization; (ii) provision (benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) non-cash equity-based compensation; (v) impairment expense; (vi) net(ii) interest and other financial costs; (vii) (income) loss(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) distributions from unconsolidated subsidiaries considering principal payments of debtnoncontrolling interests; and certain capital expenditures; (ix) distributions of cash received from Joint-Interest Acquisition entities to MPC; (x) unrealized derivative losses (gains); and (xi) acquisition costs.other adjustments, as applicable. We also use DCF, which we define as Adjusted EBITDA adjusted forfor: (i) deferred revenue impacts; (ii) sales-type lease payments, net of income; (iii) net interest and other financial costs; (iii)(iv) net maintenance capital expenditures; (v) equity method investment capital expenditures paid out; and (iv)(vi) other non-cash items. The Partnership makes a distinction between realized or unrealized gainsadjustments 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 losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded(iii) cash distributions to noncontrolling interests. We define Adjusted FCF after distributions as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversedAdjusted FCF less base distributions to common and the realized gain or loss of the contract is recorded.preferred unitholders.
We believe that the presentation of Adjusted EBITDA, DCF, Adjusted FCF and DCFAdjusted 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 most directly comparable to Adjusted FCF and Adjusted FCF after distributions is net cash provided by operating activities. Adjusted EBITDA and DCFThese non-GAAP financial measures should not be considered alternatives to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and DCFactivities 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. Adjusted EBITDA and DCFThese non-GAAP financial measures should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and DCFnon-GAAP financial measures may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Results of Operations.
Management evaluates contract performance on the basis For a reconciliation of net operating margin, a non-GAAP financialAdjusted FCF and Adjusted FCF after distributions to their most directly comparable measure which is defined as segment revenue less segment purchased product costs less realized derivative gains (losses) related to purchased product costs. These charges have been excluded for the purpose of enhancing the understanding by both managementcalculated and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our useGAAP, see Liquidity and Capital Resources.
Comparability of net operating margin andour Financial Results
During the underlying methodology in excluding certain charges is not necessarily an indicationnormal course of business, we amend or modify our contractual agreements with customers. These amendments or modifications require the resultsagreements to be reassessed under ASU No. 2016-02, Leases (“ASC 842”), which can impact the classification of operations expected inrevenues or costs associated with the future, or that we will not, in fact, incur such charges in future periods.
In evaluating our financial performance, management utilizesagreement. These reassessments may impact the segment performance measures, segment revenues and segment operating income, including total segment operating income. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 9 of the Notes to Consolidated Financial Statements for the reconciliations of these segment measures, including total segment operating income, to their respective most directly comparable GAAP measures.
COMPARABILITY OF OUR FINANCIAL RESULTS
Our acquisitions have impacted comparability of our financial results (see Note 3results.
Results of Operations
RESULTS OF OPERATIONS
The following tabletables and discussion is a summary ofsummarize our results of operations, for the three and nine months ended September 30, 2017 and 2016, including a reconciliation of Adjusted EBITDA and DCF from netNet income and netNet cash provided by operating activities, to the most directly comparable GAAP financial measures. Prior periodThis 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 September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | Variance | | 2023 | | 2022 | | Variance |
Revenues and other income: | | | | | | | | | | | |
Total revenues and other income(1) | $ | 2,912 | | | $ | 3,401 | | | $ | (489) | | | $ | 8,315 | | | $ | 8,951 | | | $ | (636) | |
Costs and expenses: | | | | | | | | | | | |
Cost of revenues (excludes items below) | 367 | | | 371 | | | (4) | | | 1,023 | | | 981 | | | 42 | |
Purchased product costs | 474 | | | 540 | | | (66) | | | 1,234 | | | 1,670 | | | (436) | |
Rental cost of sales | 20 | | | 22 | | | (2) | | | 60 | | | 101 | | | (41) | |
Rental cost of sales - related parties | 8 | | | 10 | | | (2) | | | 24 | | | 44 | | | (20) | |
Purchases - related parties | 442 | | | 364 | | | 78 | | | 1,160 | | | 1,034 | | | 126 | |
Depreciation and amortization | 301 | | | 302 | | | (1) | | | 907 | | | 925 | | | (18) | |
General and administrative expenses | 102 | | | 88 | | | 14 | | | 280 | | | 248 | | | 32 | |
Other taxes | 44 | | | 30 | | | 14 | | | 102 | | | 97 | | | 5 | |
Total costs and expenses | 1,758 | | | 1,727 | | | 31 | | | 4,790 | | | 5,100 | | | (310) | |
Income from operations | 1,154 | | | 1,674 | | | (520) | | | 3,525 | | | 3,851 | | | (326) | |
Related-party interest and other financial costs | — | | | — | | | — | | | — | | | 5 | | | (5) | |
Interest expense, net of amounts capitalized | 223 | | | 217 | | | 6 | | | 673 | | | 627 | | | 46 | |
Other financial costs, net | 2 | | | 19 | | | (17) | | | 28 | | | 59 | | | (31) | |
Income before income taxes | 929 | | | 1,438 | | | (509) | | | 2,824 | | | 3,160 | | | (336) | |
Provision for income taxes | 1 | | | 1 | | | — | | | 2 | | | 6 | | | (4) | |
Net income | 928 | | | 1,437 | | | (509) | | | 2,822 | | | 3,154 | | | (332) | |
Less: Net income attributable to noncontrolling interests | 10 | | | 9 | | | 1 | | | 28 | | | 26 | | | 2 | |
Net income attributable to MPLX LP | 918 | | | 1,428 | | | (510) | | | 2,794 | | | 3,128 | | | (334) | |
| | | | | | | | | | | |
Adjusted EBITDA attributable to MPLX LP(2) | 1,596 | | | 1,471 | | | 125 | | | 4,646 | | | 4,321 | | | 325 | |
DCF attributable to MPLX(2) | $ | 1,373 | | | $ | 1,264 | | | $ | 109 | | | $ | 3,956 | | | $ | 3,711 | | | $ | 245 | |
(1) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial information has been retrospectively adjustedstatements for additional information.
(2) Non-GAAP measure. See reconciliation below to the acquisition of HST, WHC and MPLXT.most directly comparable GAAP measures.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Total revenues and other income | $ | 980 |
| | $ | 838 |
| | $ | 142 |
| | $ | 2,782 |
| | $ | 2,181 |
| | $ | 601 |
|
Costs and expenses: | | | | | | | | | | | |
Cost of revenues (excludes items below) | 129 |
| | 122 |
| | 7 |
| | 381 |
| | 329 |
| | 52 |
|
Purchased product costs | 170 |
| | 117 |
| | 53 |
| | 441 |
| | 310 |
| | 131 |
|
Rental cost of sales | 19 |
| | 13 |
| | 6 |
| | 44 |
| | 42 |
| | 2 |
|
Rental cost of sales - related parties | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
|
Purchases - related parties | 114 |
| | 109 |
| | 5 |
| | 330 |
| | 286 |
| | 44 |
|
Depreciation and amortization | 164 |
| | 151 |
| | 13 |
| | 515 |
| | 438 |
| | 77 |
|
Impairment expense | — |
| | — |
| | — |
| | — |
| | 130 |
| | (130 | ) |
General and administrative expenses | 59 |
| | 56 |
| | 3 |
| | 174 |
| | 172 |
| | 2 |
|
Other taxes | 14 |
| | 12 |
| | 2 |
| | 40 |
| | 37 |
| | 3 |
|
Total costs and expenses | 669 |
| | 580 |
| | 89 |
| | 1,926 |
| | 1,745 |
| | 181 |
|
Income from operations | 311 |
| | 258 |
| | 53 |
| | 856 |
| | 436 |
| | 420 |
|
Related party interest and other financial costs | 1 |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | — |
|
Interest expense, net of amounts capitalized | 77 |
| | 51 |
| | 26 |
| | 217 |
| | 158 |
| | 59 |
|
Other financial costs | 15 |
| | 13 |
| | 2 |
| | 40 |
| | 37 |
| | 3 |
|
Income before income taxes | 218 |
| | 194 |
| | 24 |
| | 598 |
| | 240 |
| | 358 |
|
Provision (benefit) for income taxes | 1 |
| | — |
| | 1 |
| | 3 |
| | (12 | ) | | 15 |
|
Net income | 217 |
| | 194 |
| | 23 |
| | 595 |
| | 252 |
| | 343 |
|
Less: Net income attributable to noncontrolling interests | 1 |
| | 2 |
| | (1 | ) | | 3 |
| | 3 |
| | — |
|
Less: Net income attributable to Predecessor | — |
| | 51 |
| | (51 | ) | | 36 |
| | 149 |
| | (113 | ) |
Net income attributable to MPLX LP | $ | 216 |
| | $ | 141 |
| | $ | 75 |
| | $ | 556 |
| | $ | 100 |
| | $ | 456 |
|
| | | | | | | | | | | |
Adjusted EBITDA attributable to MPLX LP(1) | $ | 538 |
| | $ | 375 |
| | $ | 163 |
| | $ | 1,435 |
| | $ | 1,028 |
| | $ | 407 |
|
DCF(1) | 442 |
| | 301 |
| | 141 |
| | 1,183 |
| | 822 |
| | 361 |
|
DCF attributable to GP and LP unitholders(1) | 426 |
| | 285 |
| | 141 |
| | 1,134 |
| | 797 |
| | 337 |
|
| |
(1) | Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable GAAP measures. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 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 | $ | 928 | | | $ | 1,437 | | | $ | (509) | | | $ | 2,822 | | | $ | 3,154 | | | $ | (332) | |
Provision for income taxes | 1 | | | 1 | | | — | | | 2 | | | 6 | | | (4) | |
Interest and other financial costs | 225 | | | 236 | | | (11) | | | 701 | | | 691 | | | 10 | |
Income from operations | 1,154 | | | 1,674 | | | (520) | | | 3,525 | | | 3,851 | | | (326) | |
Depreciation and amortization | 301 | | | 302 | | | (1) | | | 907 | | | 925 | | | (18) | |
Income from equity method investments | (159) | | | (125) | | | (34) | | | (438) | | | (335) | | | (103) | |
Distributions/adjustments related to equity method investments | 208 | | | 166 | | | 42 | | | 551 | | | 450 | | | 101 | |
Gain on sales-type leases | — | | | (509) | | | 509 | | | — | | | (509) | | | 509 | |
Garyville Incident response costs | 63 | | | — | | | 63 | | | 63 | | | — | | | 63 | |
Other(1) | 40 | | | (27) | | | 67 | | | 69 | | | (32) | | | 101 | |
Adjusted EBITDA | 1,607 | | | 1,481 | | | 126 | | | 4,677 | | | 4,350 | | | 327 | |
Adjusted EBITDA attributable to noncontrolling interests | (11) | | | (10) | | | (1) | | | (31) | | | (29) | | | (2) | |
Adjusted EBITDA attributable to MPLX LP | 1,596 | | | 1,471 | | | 125 | | | 4,646 | | | 4,321 | | | 325 | |
Deferred revenue impacts | 25 | | | 39 | | | (14) | | | 65 | | | 87 | | | (22) | |
Sales-type lease payments, net of income | 3 | | | 3 | | | — | | | 9 | | | 13 | | | (4) | |
Net interest and other financial costs(2) | (212) | | | (216) | | | 4 | | | (650) | | | (635) | | | (15) | |
Maintenance capital expenditures, net of reimbursements | (28) | | | (40) | | | 12 | | | (93) | | | (93) | | | — | |
Equity method investment maintenance capital expenditures paid out | (4) | | | (4) | | | — | | | (11) | | | (10) | | | (1) | |
Other | (7) | | | 11 | | | (18) | | | (10) | | | 28 | | | (38) | |
DCF attributable to MPLX LP | 1,373 | | | 1,264 | | | 109 | | | 3,956 | | | 3,711 | | | 245 | |
Preferred unit distributions | (25) | | | (33) | | | 8 | | | (76) | | | (96) | | | 20 | |
DCF attributable to GP and LP unitholders | $ | 1,348 | | | $ | 1,231 | | | $ | 117 | | | $ | 3,880 | | | $ | 3,615 | | | $ | 265 | |
(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.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income: | | | | | | | | | | | |
Net income | $ | 217 |
| | $ | 194 |
| | $ | 23 |
| | $ | 595 |
| | $ | 252 |
| | $ | 343 |
|
Depreciation and amortization | 164 |
| | 151 |
| | 13 |
| | 515 |
| | 438 |
| | 77 |
|
Provision (benefit) for income taxes | 1 |
| | — |
| | 1 |
| | 3 |
| | (12 | ) | | 15 |
|
Amortization of deferred financing costs | 13 |
| | 11 |
| | 2 |
| | 38 |
| | 34 |
| | 4 |
|
Non-cash equity-based compensation | 4 |
| | 3 |
| | 1 |
| | 10 |
| | 9 |
| | 1 |
|
Impairment expense | — |
| | — |
| | — |
| | — |
| | 130 |
| | (130 | ) |
Net interest and other financial costs | 80 |
| | 53 |
| | 27 |
| | 220 |
| | 162 |
| | 58 |
|
(Income) loss from equity method investments | (23 | ) | | (6 | ) | | (17 | ) | | (29 | ) | | 72 |
| | (101 | ) |
Distributions from unconsolidated subsidiaries | 70 |
| | 33 |
| | 37 |
| | 136 |
| | 111 |
| | 25 |
|
Distributions of cash received from Joint-Interest Acquisition entities to MPC | (13 | ) | | — |
| | (13 | ) | | (13 | ) | | — |
| | (13 | ) |
Other adjustments to equity method investment distributions | 8 |
| | — |
| | 8 |
| | 8 |
| | — |
| | 8 |
|
Unrealized derivative losses (gains)(1) | 17 |
| | 2 |
| | 15 |
| | (2 | ) | | 23 |
| | (25 | ) |
Acquisition costs | 2 |
| | — |
| | 2 |
| | 6 |
| | (1 | ) | | 7 |
|
Adjusted EBITDA | 540 |
| | 441 |
| | 99 |
| | 1,487 |
| | 1,218 |
| | 269 |
|
Adjusted EBITDA attributable to noncontrolling interests | (2 | ) | | (2 | ) | | — |
| | (5 | ) | | (3 | ) | | (2 | ) |
Adjusted EBITDA attributable to Predecessor(2) | — |
| | (64 | ) | | 64 |
| | (47 | ) | | (187 | ) | | 140 |
|
Adjusted EBITDA attributable to MPLX LP | 538 |
| | 375 |
| | 163 |
| | 1,435 |
| | 1,028 |
| | 407 |
|
Deferred revenue impacts | 8 |
| | 1 |
| | 7 |
| | 25 |
| | 8 |
| | 17 |
|
Net interest and other financial costs | (80 | ) | | (53 | ) | | (27 | ) | | (220 | ) | | (162 | ) | | (58 | ) |
Maintenance capital expenditures | (24 | ) | | (25 | ) | | 1 |
| | (59 | ) | | (58 | ) | | (1 | ) |
Other | — |
| | (2 | ) | | 2 |
| | — |
| | (2 | ) | | 2 |
|
Portion of DCF adjustments attributable to Predecessor(2) | — |
| | 5 |
| | (5 | ) | | 2 |
| | 8 |
| | (6 | ) |
DCF | 442 |
| | 301 |
| | 141 |
| | 1,183 |
| | 822 |
| | 361 |
|
Preferred unit distributions | (16 | ) | | (16 | ) | | — |
| | (49 | ) | | (25 | ) | | (24 | ) |
DCF attributable to GP and LP unitholders | $ | 426 |
| | $ | 285 |
| | $ | 141 |
| | $ | 1,134 |
| | $ | 797 |
| | $ | 337 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 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 | $ | 1,244 | | | $ | 1,039 | | | $ | 205 | | | $ | 3,908 | | | $ | 3,651 | | | $ | 257 | |
Changes in working capital items | 56 | | | 208 | | | (152) | | | (56) | | | 60 | | | (116) | |
All other, net | (9) | | | (15) | | | 6 | | | (12) | | | (51) | | | 39 | |
Loss on extinguishment of debt | — | | | 1 | | | (1) | | | 9 | | | 1 | | | 8 | |
Net interest and other financial costs(1) | 212 | | | 216 | | | (4) | | | 650 | | | 635 | | | 15 | |
Other adjustments to equity method investment distributions | 13 | | | 19 | | | (6) | | | 25 | | | 45 | | | (20) | |
Garyville Incident response costs | 63 | | | — | | | 63 | | | 63 | | | — | | | 63 | |
Other | 28 | | | 13 | | | 15 | | | 90 | | | 9 | | | 81 | |
Adjusted EBITDA | 1,607 | | | 1,481 | | | 126 | | | 4,677 | | | 4,350 | | | 327 | |
Adjusted EBITDA attributable to noncontrolling interests | (11) | | | (10) | | | (1) | | | (31) | | | (29) | | | (2) | |
Adjusted EBITDA attributable to MPLX LP | 1,596 | | | 1,471 | | | 125 | | | 4,646 | | | 4,321 | | | 325 | |
Deferred revenue impacts | 25 | | | 39 | | | (14) | | | 65 | | | 87 | | | (22) | |
Sales-type lease payments, net of income | 3 | | | 3 | | | — | | | 9 | | | 13 | | | (4) | |
Net interest and other financial costs(1) | (212) | | | (216) | | | 4 | | | (650) | | | (635) | | | (15) | |
Maintenance capital expenditures, net of reimbursements | (28) | | | (40) | | | 12 | | | (93) | | | (93) | | | — | |
Equity method investment maintenance capital expenditures paid out | (4) | | | (4) | | | — | | | (11) | | | (10) | | | (1) | |
Other | (7) | | | 11 | | | (18) | | | (10) | | | 28 | | | (38) | |
DCF attributable to MPLX LP | 1,373 | | | 1,264 | | | 109 | | | 3,956 | | | 3,711 | | | 245 | |
Preferred unit distributions | (25) | | | (33) | | | 8 | | | (76) | | | (96) | | | 20 | |
DCF attributable to GP and LP unitholders | $ | 1,348 | | | $ | 1,231 | | | $ | 117 | | | $ | 3,880 | | | $ | 3,615 | | | $ | 265 | |
(1) Excludes gain/loss on extinguishment of debt and amortization of deferred financing costs. |
| | | | | | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 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 | $ | 1,338 |
| | $ | 975 |
| | $ | 363 |
|
Changes in working capital items | (41 | ) | | 59 |
| | (100 | ) |
All other, net | (43 | ) | | (18 | ) | | (25 | ) |
Non-cash equity-based compensation | 10 |
| | 9 |
| | 1 |
|
Net gain on disposal of assets | 1 |
| | 1 |
| | — |
|
Net interest and other financial costs | 220 |
| | 162 |
| | 58 |
|
Current income taxes | 1 |
| | 4 |
| | (3 | ) |
Asset retirement expenditures | 2 |
| | 4 |
| | (2 | ) |
Unrealized derivative (gains) losses(1) | (2 | ) | | 23 |
| | (25 | ) |
Acquisition costs | 6 |
| | (1 | ) | | 7 |
|
Distributions of cash received from Joint-Interest Acquisition entities to MPC | (13 | ) | | — |
| | (13 | ) |
Other adjustments to equity method investment distributions | 8 |
| | — |
| | 8 |
|
Adjusted EBITDA | 1,487 |
| | 1,218 |
| | 269 |
|
Adjusted EBITDA attributable to noncontrolling interests | (5 | ) | | (3 | ) | | (2 | ) |
Adjusted EBITDA attributable to Predecessor(2) | (47 | ) | | (187 | ) | | 140 |
|
Adjusted EBITDA attributable to MPLX LP | 1,435 |
| | 1,028 |
| | 407 |
|
Deferred revenue impacts | 25 |
| | 8 |
| | 17 |
|
Net interest and other financial costs | (220 | ) | | (162 | ) | | (58 | ) |
Maintenance capital expenditures | (59 | ) | | (58 | ) | | (1 | ) |
Other | — |
| | (2 | ) | | 2 |
|
Portion of DCF adjustments attributable to Predecessor(2) | 2 |
| | 8 |
| | (6 | ) |
DCF | 1,183 |
| | 822 |
| | 361 |
|
Preferred unit distributions | (49 | ) | | (25 | ) | | (24 | ) |
DCF attributable to GP and LP unitholders | $ | 1,134 |
| | $ | 797 |
| | $ | 337 |
|
| |
(1) | The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded. |
| |
(2) | The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the acquisition dates. |
Three months ended September 30, 20172023 compared to three months ended September 30, 20162022
Total revenues and other income increased $142decreased $489 million in the third quarter of 20172023 compared to the same period of 2016. This variance2022. The decrease was due mainly to increased pricingdriven by a contract modification that resulted in a non-cash gain on product salessales-type lease of approximately $54 million, offset by an increased unrealized derivative loss of $10 million, higher revenues from volume growth of $49 million in the Marcellus and the Southwest areas,higher crude and product transportation volumes of $14 million, a $19 million increase from the acquisition of the Ozark pipeline, a $17 million increase from our equity method investments, mainly due to the acquisition of an equity interest in the Bakken Pipeline system, the addition of the Sherwood Midstream joint venture during 2017 and increased dry gas gathering volumes for certain of our equity method investments.
Cost of revenues increased $7$509 million in the third quarter of 20172022. In addition, product sales revenue decreased as a result of lower NGL prices during the third quarter of 2023 as compared to the same period of 2016. This variance2022. The decrease was partially offset by rate escalations and higher throughput across the business and a $34 million increase in income from equity method investments primarily due to the acquisition of the Ozark pipeline.higher throughput.
Purchased product costs increased $53decreased $66 million in the third quarter of 20172023 compared to the same period of 2016.2022. This variance was primarily due to lower NGL prices of $276 million, partially offset by higher NGL and gas pricesvolumes of $36$157 million and increased volumesa change of $10$53 million primarilydue to changes in the Southwest area, as well asfair value of an increaseembedded derivative in the unrealized loss of $6 million, of which a majority isnatural gas purchase commitment.
Purchases - related to our Natural Gas Embedded Derivative.
Depreciation and amortization expenseparties increased $13$78 million in the third quarter of 20172023 compared to the same period of 2016.2022. This variance was primarily due to additions to in-service property, plantGaryville Incident response costs of $63 million and equipment as well as approximately $2 millionincreased employee costs from MPC.
Interest expense, net of accelerated depreciation related to adjustments of certain assets’ useful life.
Net interest expense and other financial costsamounts capitalized increased $28$6 million in the third quarter of 20172023 compared to the same period of 2016. The increase is mainly2022. 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 New Senior Notes issuedredemption of the 6.875 percent Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series B preferred units”) in February 2017.the first quarter of 2023. Other financial costs, net also benefited from higher interest earned during the third quarter of 2023. Refer to the Liquidity and Capital Resources section for further information.
Nine months ended September 30, 20172023 compared to nine months ended September 30, 20162022
Total revenues and other income decreased $636 million in the first ninemonths of 2023 compared to the same period of 2022. The decrease was driven by a contract modification that resulted in a non-cash gain on sales-type lease of $509 million in the third quarter of 2022 in addition to lower product sales revenue as a result of lower NGL prices during the first nine months of
2023 as compared to the same period of 2022. The decrease was partially offset by rate escalations and higher throughput across the business and a $103 million increase in income from equity method investments primarily due to higher throughput.
Cost of revenues increased $601$42 million and rental cost of sales (including related party) decreased $61 million in the first ninemonths 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 $436 million in the first nine months of 20172023 compared to the same period of 2016.2022. This variance was primarily due mainly to the inclusionlower NGL prices of $103$826 million, partially offset by higher volumes of revenue generated by MPLXT$329 million and its subsidiaries since it was not formed as a business until April 1, 2016, increased pricing on product saleschange of approximately $177$61 million as well as higher revenues from volume growth of $146 milliondue to changes in the Marcellus and the Southwest areas, higher crude and product transportation volumesfair value of $28 million, $45 million from the acquisition of the Ozark pipelineandan embedded derivative in a $12 million increase from our equity method investments. The nine months ended September 30, 2016 also included an impairment expense of $89 millionnatural gas purchase commitment.
Purchases - related to our investment in Ohio Condensate as referenced in our Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.
Cost of revenuesparties increased $52$126 million in the first nine months of 20172023 compared to the same period of 2016.2022. This variance was primarily due to $20Garyville Incident response costs of $63 million, fromhigher volumes and pricing on associated related-party purchased product costs, and higher transportation costs.
Depreciation and amortization decreased $18 million in the inclusionfirst ninemonths of MPLXT, 2023 compared to the same period of 2022. This was primarily due to lower depreciation as well as $20 million from the acquisitiona result of the Ozark pipelinederecognition 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 third quarter of 2022.
General and an increaseadministrative expenses increased $32 million in expenses relatedthe first ninemonths of 2023 compared to the timingsame period of projects.2022 due to increased costs from MPC, primarily higher employee costs, and other miscellaneous expenses.
Purchased product costsInterest expense, net of amounts capitalized increased $131$46 million in the first nine months of 20172023 compared to the same period of 2016.2022. This variance was primarily due to refinancing debt with fixed rate debt at higher NGLinterest rates in 2022 and gas prices and purchase volumes2023 in addition to taking on incremental debt in order to finance the Southwest area, offset by a $13 million unrealized gain on our Natural Gas Embedded Derivative.
Purchases-related parties increased $44 millionredemption of the Series B preferred units in the first nine monthsquarter of 2017 compared2023. Other financial costs, net also benefited from higher interest earned during 2023. Refer to the same period of 2016. The increase was primarily due to the inclusion of approximately $23 million related party purchases of MPLXT as well as general increases in employee costs due to headcount.Liquidity and Capital Resources section for further information.
Depreciation and amortization expense increased $77 million in the first nine months of 2017 compared to the same period of 2016. This variance was primarily due to accelerated depreciation expense of approximately $35 million incurred on the decommissioning of the Houston 1 facility in the Marcellus area and other various assets, approximately $10 million of additional depreciation due to the inclusion of MPLXT, as well additions to in-service property, plant and equipment during the fourth quarter of 2016 and the first nine months of 2017.
Impairment expense decreased $130 million in the first nine months of 2017 compared to the same period of 2016. This variance was due to a non-cash impairment to goodwill in two reporting units in the G&P segment during the first six months of 2016.
Net interest expense and other financial costs increased $62 million in the first nine months of 2017 compared to the same period of 2016. The increase is primarily due to the New Senior Notes issued in February 2017.
Segment Results
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 operating incomeAdjusted EBITDA. Segment Adjusted EBITDA represents income from operationsAdjusted EBITDA attributable to the reportable segments. We have investmentsAmounts included in entities that we operate that are accounted for usingnet income and excluded from Segment Adjusted EBITDA include: (i) depreciation and amortization; (ii) interest and other financial costs; (iii) income/(loss) from equity method investment accounting standards. However, we view financial informationinvestments; (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 if those investments were consolidated. Corporate general and administrative expenses, unrealized derivative (losses) gains, property, plant and equipment impairment, goodwill impairment and depreciation and amortizationapplicable. 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 allocatedtied to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to excludeoperational performance of the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC and MPLXT Predecessor prior to the March 1, 2017 acquisition.segment.
The tables below present information about segment operating incomeSegment Adjusted EBITDA for the reported segments.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Revenues and other income: | | | | | | | | | | | |
Segment revenues | $ | 378 |
| | $ | 339 |
| | $ | 39 |
| | $ | 1,095 |
| | $ | 901 |
| | $ | 194 |
|
Segment other income | 11 |
| | 12 |
| | (1 | ) | | 35 |
| | 42 |
| | (7 | ) |
Total segment revenues and other income | 389 |
| | 351 |
| | 38 |
| | 1,130 |
| | 943 |
| | 187 |
|
Costs and expenses: | | | | | | | | | | | |
Segment cost of revenues | 176 |
| | 153 |
| | 23 |
| | 500 |
| | 392 |
| | 108 |
|
Segment operating income before portion attributable to noncontrolling interests and Predecessor | 213 |
| | 198 |
| | 15 |
| | 630 |
| | 551 |
| | 79 |
|
Segment portion attributable to noncontrolling interests and Predecessor | — |
| | 74 |
| | (74 | ) | | 53 |
| | 216 |
| | (163 | ) |
Segment operating income attributable to MPLX LP | $ | 213 |
| | $ | 124 |
| | $ | 89 |
| | $ | 577 |
| | $ | 335 |
| | $ | 242 |
|
Three months ended September 30, 2017 compared to three months ended September 30, 2016
In the third quarter of 2017 compared to the same period of 2016, segment revenue increased primarily due to a $14 million increase from higher crude and product transportation volumes, a $19 million increase from the acquisition of the Ozark pipeline,a $4 million increase from the annual increase in fees and a $4 million increase from additional barges, partially offset by a $2 million decrease in the recognition of revenue related to volume deficiency payments.
In the third quarter of 2017 compared to the same period of 2016, segment cost of revenues increasedprimarily due to a $12 million increase from the acquisition of the Ozark pipeline, as well as from salaries and compensation due to headcount and other miscellaneous expenses.
In the third quarter of 2017 compared to the same period of 2016, the segment portion attributable to noncontrolling interests and Predecessor decreased due to the acquisition of HST, WHC and MPLXT as of March 1, 2017.
Nine months ended September 30, 2017 compared to nine months ended September 30, 2016
In the first nine months of 2017 compared to the same period of 2016, segment revenue increased primarily due to the inclusion of $103 million of revenue generated by MPLXT and its subsidiaries, a $28 million increase from higher crude and product transportation volumes,a $45 million increase from the acquisition of the Ozark pipeline, a $3 million increase due to the recognition of revenues related to volume deficiency payments,and a $10 million increase from additional barges.
In the first nine months of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to the acquisitions of MPLXT and the Ozark pipeline, increased expenses related to the timing of projects, salaries and compensation due to headcount, and other miscellaneous expenses.
In the first nine months of 2017 compared to the same period of 2016, the segment portion attributable to noncontrolling interests and Predecessor decreased due to the inclusion of HSM for the first three months of 2016 and the acquisition of HST, WHC and MPLXT as of March 1, 2017.
During both the third quarter and first nine months of 2017, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, for the first nine months, MPC was obligated to make a $37 million deficiency payment, of which $11 million was paid in the third quarter of 2017. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. In the third quarter and first nine months of 2017, we recognized revenue of $7 million and $29 million, respectively, related to volume deficiency credits. At September 30, 2017, the cumulative balance of Deferred revenue-related parties on our Consolidated Balance Sheets related to volume deficiencies was $55 million. The following table presents the future expiration dates of the associated deferred revenue credits as of September 30, 2017:
|
| | | |
(In millions) | |
December 31, 2017 | $ | 8 |
|
March 31, 2018 | 11 |
|
June 30, 2018 | 11 |
|
September 30, 2018 | 10 |
|
December 31, 2018 | 4 |
|
March 31, 2019 | 3 |
|
June 30, 2019 | 4 |
|
September 30, 2019 | 4 |
|
Total | $ | 55 |
|
We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period. Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.
G&P Segment
Our assets include approximately 5.9 bcf/d of gathering capacity, 7.8 bcf/d of natural gas processing capacity and 570 mbpd of fractionation capacity.
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Revenues and other income: | | | | | | | | | | | |
Segment revenues | $ | 669 |
| | $ | 567 |
| | $ | 102 |
| | $ | 1,869 |
| | $ | 1,595 |
| | $ | 274 |
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Segment other income | 1 |
| | 1 |
| | — |
| | 2 |
| | 1 |
| | 1 |
|
Total segment revenues and other income | 670 |
| | 568 |
| | 102 |
| | 1,871 |
| | 1,596 |
| | 275 |
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Costs and expenses: | | | | | | | | | | | |
Segment cost of revenues | 276 |
| | 239 |
| | 37 |
| | 781 |
| | 662 |
| | 119 |
|
Segment operating income before portion attributable to noncontrolling interests | 394 |
| | 329 |
| | 65 |
| | 1,090 |
| | 934 |
| | 156 |
|
Segment portion attributable to noncontrolling interests | 45 |
| | 36 |
| | 9 |
| | 119 |
| | 113 |
| | 6 |
|
Segment operating income attributable to MPLX LP | $ | 349 |
| | $ | 293 |
| | $ | 56 |
| | $ | 971 |
| | $ | 821 |
| | $ | 150 |
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Three months ended September 30, 2017 compared to three months ended September 30, 2016
In the third quarter of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $46 million and increased volumes of $15 million, combined with increased fees of approximately $41 million on higher volumes due to new gathering and processing facilities in the Marcellus, Southwest, and Utica areas, as well as additional fractionation capacity in the Marcellus and Utica areas.
In the third quarter of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to increased product costs resulting from higher NGL and gas prices of $28 million and increased volumes of $10 million primarily in the Southwest area partially offset by lower maintenance costs and other operating efficiencies.
Nine months ended September 30, 2017 compared to nine months ended September 30, 2016
In the first nine months of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $144 million and increased volumes of $38 million, combined with increased fees of approximately $92 million on higher volumes due to new processing plants in the Marcellus and Southwest areas and additional fractionation capacity in the Marcellus and Utica areas.
In the first nine months of 2017 compared to the same period of 2016, segment cost of revenues increased due primarily to increased product costs resulting from higher prices of approximately $102 million and higher volumes of $21 million primarily in the Southwest area partially offset by lower facility costs due to lower maintenance costs and other operating efficiencies.
Segment Reconciliations
The following tables provide reconciliations of segment operating income to our consolidated income from operations, segment revenue to our consolidated total revenues and other income, and segment portion attributable to noncontrolling interests to our consolidated net income attributable to noncontrolling interestssegments for the three and nine months ended September 30, 20172023 and 2016. Adjustments relatedSeptember 30, 2022.
L&S Segment
Third Quarter L&S Segment Financial Highlights (in millions)
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | Variance | | 2023 | | 2022 | | Variance |
Service revenue | $ | 1,130 | | | $ | 1,038 | | | $ | 92 | | | $ | 3,223 | | | $ | 3,031 | | | $ | 192 | |
Rental income | 216 | | | 210 | | | 6 | | | 638 | | | 593 | | | 45 | |
Product related revenue | 6 | | | 4 | | | 2 | | | 14 | | | 15 | | | (1) | |
Sales-type lease revenue | 129 | | | 118 | | | 11 | | | 379 | | | 343 | | | 36 | |
Income from equity method investments | 95 | | | 72 | | | 23 | | | 248 | | | 183 | | | 65 | |
Other income | 15 | | | 8 | | | 7 | | | 47 | | | 42 | | | 5 | |
Total segment revenues and other income | 1,591 | | | 1,450 | | | 141 | | | 4,549 | | | 4,207 | | | 342 | |
Cost of revenues | 158 | | | 160 | | | (2) | | | 451 | | | 460 | | | (9) | |
Purchases - related parties | 341 | | | 265 | | | 76 | | | 848 | | | 762 | | | 86 | |
Depreciation and amortization | 130 | | | 128 | | | 2 | | | 399 | | | 387 | | | 12 | |
General and administrative expenses | 60 | | | 48 | | | 12 | | | 160 | | | 134 | | | 26 | |
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Other taxes | 32 | | | 19 | | | 13 | | | 71 | | | 60 | | | 11 | |
Total costs and expenses | 721 | | | 620 | | | 101 | | | 1,929 | | | 1,803 | | | 126 | |
Segment income from operations | 870 | | | 830 | | | 40 | | | 2,620 | | | 2,404 | | | 216 | |
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Segment Adjusted EBITDA | 1,091 | | | 969 | | | 122 | | | 3,139 | | | 2,839 | | | 300 | |
Capital expenditures | 73 | | | 80 | | | (7) | | | 251 | | | 238 | | | 13 | |
Investments in unconsolidated affiliates(1) | $ | 7 | | | $ | 12 | | | $ | (5) | | | $ | 23 | | | $ | 90 | | | $ | (67) | |
(1) The nine months ended September 30, 2022 includes a contribution of $60 million to unconsolidated affiliates relatea 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, to fund our Partnership-operated non-wholly-owned entities that we consolidate for segment purposes. share of a debt repayment by the joint venture.
Three months ended September 30, 2023 compared to three months ended September 30, 2022
Service revenue increased $92 million in the third quarter of 2023 compared to the same period of 2022. This was primarily driven by higher pipeline tariff rates, increased pipeline throughput, and $15 million from refining logistics fee escalations.
Sales-type lease revenue increased $11 million in the third quarter of 2023 compared to the same period of 2022. This was due to an increase of $5 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, with the remainder being attributable to fee escalations.
Income (loss) from equity method investmentsrelates increased $23 million in the third quarter of 2023 compared to our portionthe same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.
Purchases - related parties increased $76 million in the third quarter of 2023 compared to the same period of 2022, primarily due to Garyville Incident response costs of $63 million and increased employee costs from MPC.
General and administrative expenses increased $12 million in the first nine months of 2023 compared to the same period of 2022, due to increased costs from MPC, primarily higher employee costs, as well as other miscellaneous increases.
Nine months ended September 30, 2023 compared to nine months ended September 30, 2022
Service revenue increased $192 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to higher pipeline tariff rates and increased pipeline throughput, and $32 million from refining logistics fee escalations. These increases were partially offset by a decrease of $41 million from changes in the presentation of revenue between service revenue, rental income (loss)and sales-type lease revenue driven by modifications to agreements with MPC.
Rental income increased $45 million in the first nine 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 driven by modifications to agreements with MPC. The remaining increase was primarily due to the escalation of storage fees.
Sales-type lease revenue increased $36 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to an increase of $23 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 $12 million from refining logistics due to fee escalations.
Income from equity method investments increased $65 million in the first nine months of 2023 compared to the same period of 2022. This was primarily driven by increased throughput on equity method investment pipeline systems.
Purchases - related parties increased $86 million in the first nine months of 2023 compared to the same period of 2022, primarily due to Garyville Incident response costs of $63 million and increased employee costs from MPC.
General and administrative expenses increased $26 million in the first nine months of 2023 compared to the same period of 2022, due to increased costs from MPC, primarily higher employee costs, as well as other miscellaneous increases.
L&S Operating Data
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
L&S | | | | | | | |
Pipeline throughput (mbpd) | | | | | | | |
Crude oil pipelines | 3,911 | | | 3,596 | | | 3,796 | | | 3,551 | |
Product pipelines | 1,975 | | | 2,169 | | | 2,027 | | | 2,125 | |
Total pipelines | 5,886 | | | 5,765 | | | 5,823 | | | 5,676 | |
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Average tariff rates ($ per barrel)(1) | | | | | | | |
Crude oil pipelines | $ | 0.99 | | | $ | 0.93 | | | $ | 0.95 | | | $ | 0.91 | |
Product pipelines | 0.99 | | | 0.80 | | | 0.88 | | | 0.80 | |
Total pipelines | $ | 0.99 | | | $ | 0.88 | | | $ | 0.93 | | | $ | 0.86 | |
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Terminal throughput (mbpd) | 3,228 | | | 3,026 | | | 3,167 | | | 3,023 | |
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Marine Assets (number in operation)(2) | | | | | | | |
Barges | 305 | | | 296 | | | 305 | | | 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.
G&P Segment
Third Quarter G&P Segment Financial Highlights (in millions)
(1) The 2022 amount includes a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 | | Variance | | 2023 | | 2022 | | Variance |
Service revenue | $ | 549 | | | $ | 537 | | | $ | 12 | | | $ | 1,620 | | | $ | 1,528 | | | $ | 92 | |
Rental income | 52 | | | 66 | | | (14) | | | 155 | | | 239 | | | (84) | |
Product related revenue | 598 | | | 742 | | | (144) | | | 1,629 | | | 2,263 | | | (634) | |
Sales-type lease revenue | 34 | | | 28 | | | 6 | | | 101 | | | 28 | | | 73 | |
Income from equity method investments | 64 | | | 53 | | | 11 | | | 190 | | | 152 | | | 38 | |
Other income(1) | 24 | | | 525 | | | (501) | | | 71 | | | 534 | | | (463) | |
Total segment revenues and other income | 1,321 | | | 1,951 | | | (630) | | | 3,766 | | | 4,744 | | | (978) | |
Cost of revenues | 237 | | | 243 | | | (6) | | | 656 | | | 666 | | | (10) | |
Purchased product costs | 474 | | | 540 | | | (66) | | | 1,234 | | | 1,670 | | | (436) | |
Purchases - related parties | 101 | | | 99 | | | 2 | | | 312 | | | 272 | | | 40 | |
Depreciation and amortization | 171 | | | 174 | | | (3) | | | 508 | | | 538 | | | (30) | |
General and administrative expenses | 42 | | | 40 | | | 2 | | | 120 | | | 114 | | | 6 | |
Other taxes | 12 | | | 11 | | | 1 | | | 31 | | | 37 | | | (6) | |
Total costs and expenses | 1,037 | | | 1,107 | | | (70) | | | 2,861 | | | 3,297 | | | (436) | |
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Segment Adjusted EBITDA | 505 | | | 502 | | | 3 | | | 1,507 | | | 1,482 | | | 25 | |
Capital expenditures | 151 | | | 146 | | | 5 | | | 417 | | | 336 | | | 81 | |
Investments in unconsolidated affiliates | $ | 6 | | | $ | 30 | | | $ | (24) | | | $ | 67 | | | $ | 108 | | | $ | (41) | |
(1) The three and nine months ended September 30, 2022 include a $509 million non-cash gain on a lease reclassification. See Note 14 in the unaudited consolidated financial statements for additional information.
Three months ended September 30, 2023 compared to three months ended September 30, 2022
Service revenue increased $12 million in the third 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.
Rental income decreased $14 million and sales-type lease revenue increased $6 million in the third quarter of 2023 compared to the same period of 2022. The net decrease was primarily due to a contract modification that decreased the amount of revenue allocated to Rental income in Southern Appalachia beginning in the first quarter of 2023, partially offset by higher volumes and higher throughput fee rates.
Product related revenue decreased $144 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices across all regions of $310 million, partially offset by higher volumes in the Southwest of $175 million.
Income from equity method investments increased $11 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our unconsolidated joint ventures of which Partnership-operated joint ventures are consolidated for segment purposes. Other income-related parties consists of operational service fee revenues from our operated unconsolidated affiliates. Unrealized derivative activity is not allocated to segments.in the Marcellus and Utica. Additionally,
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Reconciliation to Income from operations: | | | | | | | | | | | |
L&S segment operating income attributable to MPLX LP | $ | 213 |
| | $ | 124 |
| | $ | 89 |
| | $ | 577 |
| | $ | 335 |
| | $ | 242 |
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G&P segment operating income attributable to MPLX LP | 349 |
| | 293 |
| | 56 |
| | 971 |
| | 821 |
| | 150 |
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Segment operating income attributable to MPLX LP | 562 |
| | 417 |
| | 145 |
| | 1,548 |
| | 1,156 |
| | 392 |
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Segment portion attributable to unconsolidated affiliates | (47 | ) | | (41 | ) | | (6 | ) | | (125 | ) | | (130 | ) | | 5 |
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Segment portion attributable to Predecessor | — |
| | 74 |
| | (74 | ) | | 53 |
| | 216 |
| | (163 | ) |
Income (loss) from equity method investments | 23 |
| | 6 |
| | 17 |
| | 29 |
| | (72 | ) | | 101 |
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Other income - related parties | 13 |
| | 11 |
| | 2 |
| | 38 |
| | 29 |
| | 9 |
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Unrealized derivative (losses) gains(1) | (17 | ) | | (2 | ) | | (15 | ) | | 2 |
| | (23 | ) | | 25 |
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Depreciation and amortization | (164 | ) | | (151 | ) | | (13 | ) | | (515 | ) | | (438 | ) | | (77 | ) |
Impairment expense | — |
| | — |
| | — |
| | — |
| | (130 | ) | | 130 |
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General and administrative expenses | (59 | ) | | (56 | ) | | (3 | ) | | (174 | ) | | (172 | ) | | (2 | ) |
Income from operations | $ | 311 |
| | $ | 258 |
| | $ | 53 |
| | $ | 856 |
| | $ | 436 |
| | $ | 420 |
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Reconciliation to Total revenues and other income: | | | | | | | | | | | |
Total segment revenues and other income | $ | 1,059 |
| | $ | 919 |
| | $ | 140 |
| | $ | 3,001 |
| | $ | 2,539 |
| | $ | 462 |
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Revenue adjustment from unconsolidated affiliates | (107 | ) | | (100 | ) | | (7 | ) | | (287 | ) | | (303 | ) | | 16 |
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Income (loss) from equity method investments | 23 |
| | 6 |
| | 17 |
| | 29 |
| | (72 | ) | | 101 |
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Other income - related parties | 13 |
| | 11 |
| | 2 |
| | 38 |
| | 29 |
| | 9 |
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Unrealized derivative (losses) gains related to product sales(1) | (8 | ) | | 2 |
| | (10 | ) | | 1 |
| | (12 | ) | | 13 |
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Total revenues and other income | $ | 980 |
| | $ | 838 |
| | $ | 142 |
| | $ | 2,782 |
| | $ | 2,181 |
| | $ | 601 |
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(1) | The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded. |
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| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Reconciliation to Net income attributable to noncontrolling interests and Predecessor: | | | | | | | | | | | |
Segment portion attributable to noncontrolling interests and Predecessor | $ | 45 |
| | $ | 110 |
| | $ | (65 | ) | | $ | 172 |
| | $ | 329 |
| | $ | (157 | ) |
Portion of noncontrolling interests and Predecessor related to items below segment income from operations | (21 | ) | | (39 | ) | | 18 |
| | (84 | ) | | (157 | ) | | 73 |
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Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates | (23 | ) | | (18 | ) | | (5 | ) | | (49 | ) | | (20 | ) | | (29 | ) |
Net income attributable to noncontrolling interests and Predecessor | $ | 1 |
| | $ | 53 |
| | $ | (52 | ) | | $ | 39 |
| | $ | 152 |
| | $ | (113 | ) |
OUR G&P CONTRACTS WITH THIRD PARTIES
We generate the majority of our revenues in the G&P segment from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contracts to provide services under the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. See Item 1. Business – Our G&P Contracts With Third Parties in our Annual Report on Form 10-K for the year ended December 31, 2016 for further discussion of each of these types of arrangements.
The following table does not give effect to our active commodity risk management program. For further discussion of how we manage commodity price volatility for the portion of our net operating margin that is not fee-based, see Note 13 of the Notes to Consolidated Financial Statements. We manage our business by taking into account the partial offset of short natural gas positions primarilyjoint venture in the Southwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.
Other income decreased $501 million in the third quarter of 2023 compared to the same period of 2022 due primarily to a non-cash gain on lease reclassification of $509 million in the third quarter of 2022.
Purchased product costs decreased $66 million in the third quarter of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices in the Southwest and Southern Appalachia of $276 million, partially offset by higher NGL volumes in the Southwest of $157 million and a change of $53 million due to changes in the fair value of an embedded derivative in a natural gas purchase commitment.
Nine months ended September 30, 2023 compared to nine months ended September 30, 2022
Service revenue increased $92 million in the first nine months 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 $84 million and sales-type lease revenue increased $73 million in the first nine 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. In addition, a contract modification decreased the amount of revenue allocated to Rental income in Southern Appalachia beginning in the first quarter 2023.
Product related revenue decreased $634 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to lower prices across all regions of $958 million, partially offset by higher volumes in the Southwest of $322 million.
Income from equity method investments increased $38 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to higher volumes associated with several of our G&P segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-indexjoint ventures in the Marcellus and keep-whole contracts reflectUtica. Additionally, our joint venture in the partialSouthwest region added processing capacity in the fourth quarter of 2022 driving higher volumes over the prior period.
Other income decreased $463 million in the first nine months of 2023 compared to the same period of 2022 due primarily to a non-cash gain on lease reclassification of $509 million in the third quarter of 2022 partially offset by the impact of ourasset disposals year over year.
Purchased product costs decreased $436 million in the first nine months of 2023 compared to the same period of 2022. This was primarily due to lower NGL prices of $826 million in the Southwest and Southern Appalachia, partially offset by higher volumes in the Southwest of $329 million and a change of $61 million due to changes in the fair value of an embedded derivative in a natural gas positions.purchase commitment.
Purchases - related parties increased $40 million in the first nine months of 2023 compared to the same period of 2022. The calculated percentages are less than one percent for percent-of-indexincrease 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 $30 million in the first nine 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 third quarter of our natural gas positions2022.
G&P Operating Data
(1) Other includes Southern Appalachia, Bakken and therefore, not meaningful toRockies Operations.
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| MPLX LP(1) | | MPLX LP Operated(2) |
| Three Months Ended September 30, | | Three Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
G&P | | | | | | | |
Gathering Throughput (MMcf/d) | | | | | | | |
Marcellus Operations | 1,376 | | | 1,325 | | | 1,376 | | | 1,325 | |
Utica Operations | — | | | — | | | 2,375 | | | 2,381 | |
Southwest Operations | 1,302 | | | 1,362 | | | 1,742 | | | 1,642 | |
Bakken Operations | 160 | | | 147 | | | 160 | | | 147 | |
Rockies Operations | 490 | | | 452 | | | 604 | | | 588 | |
Total gathering throughput | 3,328 | | | 3,286 | | | 6,257 | | | 6,083 | |
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Natural Gas Processed (MMcf/d) | | | | | | | |
Marcellus Operations | 4,187 | | | 4,060 | | | 5,803 | | | 5,535 | |
Utica Operations | — | | | — | | | 557 | | | 518 | |
Southwest Operations | 1,405 | | | 1,502 | | | 1,744 | | | 1,666 | |
Southern Appalachian Operations | 207 | | | 205 | | | 207 | | | 205 | |
Bakken Operations | 159 | | | 130 | | | 159 | | | 130 | |
Rockies Operations | 491 | | | 462 | | | 491 | | | 462 | |
Total natural gas processed | 6,449 | | | 6,359 | | | 8,961 | | | 8,516 | |
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C2 + NGLs Fractionated (mbpd) | | | | | | | |
Marcellus Operations(3) | 546 | | | 496 | | | 546 | | | 496 | |
Utica Operations(3) | — | | | — | | | 34 | | | 30 | |
Southern Appalachian Operations | 10 | | | 12 | | | 10 | | | 12 | |
Bakken Operations | 20 | | | 21 | | | 20 | | | 21 | |
Rockies Operations | 3 | | | 3 | | | 3 | | | 3 | |
Total C2 + NGLs fractionated(4) | 579 | | | 532 | | | 613 | | | 562 | |
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| MPLX LP(1) | | MPLX LP Operated(2) |
| Nine Months Ended September 30, | | Nine Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
G&P | | | | | | | |
Gathering Throughput (MMcf/d) | | | | | | | |
Marcellus Operations | 1,353 | | | 1,308 | | | 1,353 | | | 1,308 | |
Utica Operations | — | | | — | | | 2,387 | | | 2,048 | |
Southwest Operations | 1,345 | | | 1,367 | | | 1,775 | | | 1,605 | |
Bakken Operations | 159 | | | 147 | | | 159 | | | 147 | |
Rockies Operations | 463 | | | 424 | | | 584 | | | 556 | |
Total gathering throughput | 3,320 | | | 3,246 | | | 6,258 | | | 5,664 | |
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Natural Gas Processed (MMcf/d) | | | | | | | |
Marcellus Operations | 4,107 | | | 4,021 | | | 5,683 | | | 5,503 | |
Utica Operations | — | | | — | | | 533 | | | 488 | |
Southwest Operations | 1,442 | | | 1,446 | | | 1,771 | | | 1,616 | |
Southern Appalachian Operations | 219 | | | 220 | | | 219 | | | 220 | |
Bakken Operations | 157 | | | 138 | | | 157 | | | 138 | |
Rockies Operations | 472 | | | 436 | | | 472 | | | 436 | |
Total natural gas processed | 6,397 | | | 6,261 | | | 8,835 | | | 8,401 | |
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C2 + NGLs Fractionated (mbpd) | | | | | | | |
Marcellus Operations(3) | 533 | | | 478 | | | 533 | | | 478 | |
Utica Operations(3) | — | | | — | | | 31 | | | 28 | |
Southern Appalachian Operations | 10 | | | 11 | | | 10 | | | 11 | |
Bakken Operations | 19 | | | 21 | | | 19 | | | 21 | |
Rockies Operations | 3 | | | 3 | | | 3 | | | 3 | |
Total C2 + NGLs fractionated(4) | 565 | | | 513 | | | 596 | | | 541 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
Pricing Information | | | | | | | |
Natural Gas NYMEX HH ($ per MMBtu) | $ | 2.66 | | | $ | 7.91 | | | $ | 2.58 | | | $ | 6.67 | |
C2 + NGL Pricing ($ per gallon)(5) | $ | 0.68 | | | $ | 1.01 | | | $ | 0.69 | | | $ | 1.11 | |
(1) This column represents operating data for entities that have been consolidated into the table below.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.
For(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 246 mbpd and 210 mbpd of MPLX LP consolidated total fractionated products for the three months ended September 30, 2017, we calculated the following approximate percentages2023 and September 30, 2022, respectively, and approximately 240 mbpd and 195 mbpd of our net operating margin from the following types of contracts:
|
| | | | | | | | |
| Fee-Based | | Percent-of-Proceeds(1) | | Keep-Whole(2) |
L&S | 100 | % | | — | % | | — | % |
G&P(3) | 86 | % | | 12 | % | | 2 | % |
Total | 92 | % | | 7 | % | | 1 | % |
Fortotal fractionated products for the nine months ended September 30, 2017, we calculated2023 and September 30, 2022, respectively. Purity ethane makes up approximately 254 mbpd and 217 mbpd of MPLX LP Operated total fractionated products for the following approximate percentagesthree months ended September 30, 2023 and September 30, 2022, respectively, and approximately 246 mbpd and 200 mbpd of our net operating margin fromtotal fractionated products for the following typesnine months ended September 30, 2023 and September 30, 2022, respectively.
(5) C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of contracts:approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
Seasonality
|
| | | | | | | | |
| Fee-Based | | Percent-of-Proceeds(1) | | Keep-Whole(2) |
L&S | 100 | % | | — | % | | — | % |
G&P(3) | 87 | % | | 11 | % | | 2 | % |
Total | 93 | % | | 6 | % | | 1 | % |
| |
(1) | Includes condensate sales and other types of arrangements tied to NGL prices. |
| |
(2) | Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices. |
| |
(3) | Includes unconsolidated affiliates (See Note 4 of the Notes to Consolidated Financial Statements). |
The following table presents a reconciliation of net operating margin to income from operations, the most directly comparable GAAP financial measure.
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Reconciliation of net operating margin to income from operations: | | | | | | | |
Segment revenues | $ | 1,047 |
| | $ | 906 |
| | $ | 2,964 |
| | $ | 2,496 |
|
Purchased product costs | (170 | ) | | (117 | ) | | (441 | ) | | (310 | ) |
Total derivative loss related to purchased product costs | 11 |
| | 4 |
| | 5 |
| | 16 |
|
Other | (1 | ) | | — |
| | (5 | ) | | (5 | ) |
Net operating margin | 887 |
| | 793 |
| | 2,523 |
| | 2,197 |
|
Revenue adjustment from unconsolidated affiliates(2) | (107 | ) | | (100 | ) | | (287 | ) | | (303 | ) |
Realized derivative loss related to purchased product costs(1) | (2 | ) | | (1 | ) | | (6 | ) | | (4 | ) |
Other | 2 |
| | 1 |
| | 6 |
| | 4 |
|
Unrealized derivative (losses) gains(1) | (17 | ) | | (2 | ) | | 2 |
| | (23 | ) |
Income (loss) from equity method investments | 23 |
| | 6 |
| | 29 |
| | (72 | ) |
Other income | 2 |
| | 2 |
| | 5 |
| | 5 |
|
Other income - related parties | 22 |
| | 22 |
| | 69 |
| | 67 |
|
Cost of revenues (excludes items below) | (129 | ) | | (122 | ) | | (381 | ) | | (329 | ) |
Rental cost of sales | (19 | ) | | (13 | ) | | (44 | ) | | (42 | ) |
Rental cost of sales - related parties | — |
| | — |
| | (1 | ) | | (1 | ) |
Purchases - related parties | (114 | ) | | (109 | ) | | (330 | ) | | (286 | ) |
Depreciation and amortization | (164 | ) | | (151 | ) | | (515 | ) | | (438 | ) |
Impairment expense | — |
| | — |
| | — |
| | (130 | ) |
General and administrative expenses | (59 | ) | | (56 | ) | | (174 | ) | | (172 | ) |
Other taxes | (14 | ) | | (12 | ) | | (40 | ) | | (37 | ) |
Income from operations | $ | 311 |
| | $ | 258 |
| | $ | 856 |
| | $ | 436 |
|
| |
(1) | The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded. |
| |
(2) | These amounts relate to Partnership-operated unconsolidated affiliates. The chief operating decision maker and management include these to evaluate the segment performance as we continue to operate and manage the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed for GAAP purposes. |
SEASONALITY
The volume of crude oil and refined products transported on our pipeline systems, at our barge dock and stored atutilizing our storage assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. ManyThe majority of effects of seasonality on the L&S segment’s revenues will beare mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments.
In our G&P segment, can be affected bywe experience minimal impacts from seasonal fluctuations inwhich impact the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns andincluding variations in weather patterns from year to year. However, weWe are able to manage the seasonality impactimpacts through the execution of our marketing strategy. We have access to up to 50 million gallons of propane storage capacity in the Southern Appalachia region provided by an arrangement with a third party which provides us with flexibility to manage the seasonality impact. Overall, our exposure to the seasonalseasonality fluctuations in the commodity markets is declininglimited due to the nature of our growth in fee-based business.
55Liquidity and Capital Resources
OPERATING DATA
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2017 | | 2016 | | 2017 | | 2016 |
L&S | | | | | | | |
Pipeline throughput (mbpd)(1) | | | | | | | |
Crude oil pipelines | 2,046 |
| | 1,775 |
| | 1,901 |
| | 1,665 |
|
Product pipelines | 1,131 |
| | 992 |
| | 1,051 |
| | 989 |
|
Total pipelines | 3,177 |
| | 2,767 |
| | 2,952 |
| | 2,654 |
|
| | | | | | | |
Average tariff rates ($ per barrel)(1)(2) | | | | | | | |
Crude oil pipelines | $ | 0.54 |
| | $ | 0.55 |
| | $ | 0.57 |
| | $ | 0.57 |
|
Product pipelines | 0.75 |
| | 0.69 |
| | 0.74 |
| | 0.67 |
|
Total pipelines | 0.62 |
| | 0.60 |
| | 0.63 |
| | 0.61 |
|
| | | | | | | |
Terminal throughput (mbpd) | 1,496 |
| | 1,517 |
| | 1,470 |
| | 1,510 |
|
| | | | | | | |
Marine Assets (number in operation)(3) | | | | | | | |
Barges | 232 |
| | 217 |
| | 232 |
| | 217 |
|
Towboats | 18 |
| | 18 |
| | 18 |
| | 18 |
|
| | | | | | | |
G&P | | | | | | | |
Gathering Throughput (MMcf/d) | | | | | | | |
Marcellus Operations | 1,005 |
| | 946 |
| | 965 |
| | 922 |
|
Utica Operations(4) | 1,324 |
| | 916 |
| | 1,065 |
| | 936 |
|
Southwest Operations(5) | 1,400 |
| | 1,444 |
| | 1,385 |
| | 1,455 |
|
Total gathering throughput | 3,729 |
| | 3,306 |
| | 3,415 |
| | 3,313 |
|
| | | | | | | |
Natural Gas Processed (MMcf/d) | | | | | | | |
Marcellus Operations | 3,986 |
| | 3,273 |
| | 3,778 |
| | 3,166 |
|
Utica Operations(4) | 1,000 |
| | 1,050 |
| | 982 |
| | 1,068 |
|
Southwest Operations | 1,331 |
| | 1,339 |
| | 1,310 |
| | 1,209 |
|
Southern Appalachian Operations | 264 |
| | 244 |
| | 266 |
| | 248 |
|
Total natural gas processed | 6,581 |
| | 5,906 |
| | 6,336 |
| | 5,691 |
|
| | | | | | | |
C2 + NGLs Fractionated (mbpd) | | | | | | | |
Marcellus Operations(6) | 326 |
| | 274 |
| | 310 |
| | 254 |
|
Utica Operations(4)(6) | 39 |
| | 41 |
| | 40 |
| | 43 |
|
Southwest Operations | 18 |
| | 19 |
| | 19 |
| | 17 |
|
Southern Appalachian Operations(7) | 14 |
| | 14 |
| | 15 |
| | 16 |
|
Total C2 + NGLs fractionated(8) | 397 |
| | 348 |
| | 384 |
| | 330 |
|
| | | | | | | |
Pricing Information | | | | | | | |
Natural Gas NYMEX HH ($ per MMBtu) | $ | 2.96 |
| | $ | 2.80 |
| | $ | 3.05 |
| | $ | 2.34 |
|
C2 + NGL Pricing ($ per gallon)(9) | $ | 0.66 |
| | $ | 0.46 |
| | $ | 0.62 |
| | $ | 0.44 |
|
| |
(1) | Pipeline throughput and tariff rates as of September 30, 2016 have been retrospectively adjusted to reflect the acquisition of HST. |
| |
(2) | Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels. |
| |
(3) | Represents total at end of period. |
| |
(4) | Includes unconsolidated equity method investments that are shown consolidated for segment purposes only. |
| |
(5) | Includes approximately two MMcf/d related to the unconsolidated equity method investment, Wirth, for the three months ended September 30, 2017, and 230 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the nine months ended September 30, 2017. Includes approximately 307 MMcf/d and 299 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and nine months ended September 30, 2016, respectively. |
| |
(6) | Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator. |
| |
(7) | Includes NGLs fractionated for the Marcellus Operations and Utica Operations. |
| |
(8) | Purity ethane makes up approximately 164 mbpd and 160 mbpd of total fractionated products for the three and nine months ended September 30, 2017, respectively, and approximately 137 mbpd and 125 mbpd of total fractionated products for the three and nine months ended September 30, 2016, respectively. |
| |
(9) | 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. |
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Our cash and cash equivalents balance was $3were $960 million at September 30, 2017 compared to $2342023 and $238 million at December 31, 2016.2022. 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:
| | | Nine Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | (In millions) | 2023 | | 2022 |
Net cash provided by (used in): | | | | Net cash provided by (used in): | | | |
Operating activities | $ | 1,338 |
| | $ | 975 |
| Operating activities | $ | 3,908 | | | $ | 3,651 | |
Investing activities | (1,837 | ) | | (892 | ) | Investing activities | (727) | | | (676) | |
Financing activities | 268 |
| | 82 |
| Financing activities | (2,459) | | | (2,867) | |
Total | $ | (231 | ) | | $ | 165 |
| Total | $ | 722 | | | $ | 108 | |
Net cash provided by operating activities increased $363$257 million in the first nine months of 20172023 compared to the same period of 2022, primarily due to improved results from operations and favorable working capital changes during the first nine months of 2016, the majority of which is related to an increase in adjusted EBITDA of $269 million. The favorable change in adjusted EBITDA was driven primarily by higher prices and volumes, the inclusion of MPLXT, since it was not formed as a business until April 1, 2016, and the acquisition of the Ozark pipeline. In addition, there was an increase in distributions received from unconsolidated affiliates of $25 million due2022 compared to the acquisitionsame period of an equity interest in the Bakken Pipeline system and the joint-interest acquisitions.2023.
Net cash used in investing activities increased $945$51 million in the first nine months of 20172023 compared to the first nine monthssame period of 2016, primarily2022, due to the acquisition of an equity interest in the Bakken Pipeline system for $513 million, investments in other unconsolidated entities of approximately $177 million, $219 million for the acquisition of the Ozark pipeline, $30 million for the buy-out of an equity method investment partner, anhigher capital spending. The increase in cash used for additions to property, plant and equipment related to various capital projects, as well as a net decrease of $23 million in investment loans with MPC. Partially offsetting these items was a return of capital of $24 million from our acquisition of equity interests in Sherwood Midstream and Sherwood Midstream Holdings.
Financing activities were a $268 million source of cash in the first nine months of 2017 compared2023 was partially offset by higher contributions to equity method investments for the first half of 2022, which included a $82$60 million sourcecontribution to Dakota Access to fund our share of a scheduled debt repayment by the joint venture.
Net cash used in financing activities decreased $408 million in the first nine months of 2016.2023 compared to the same period of 2022. The sourcedecrease 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 $861 million. There were no unit repurchases in the first nine months of 20172023 resulting in a $315 million lower use of cash as compared to the same period of 2022. The decrease in the use of cash was primarily due to $2.2 billion of net proceeds from the New Senior Notes, $420 million of proceeds under the bank revolving credit facility, $128 million in contributions from noncontrolling interests and $483 million of net proceeds from sales of units under the ATM Program. These items were partially offset by distributionsthe use of $600 million to MPC of $1.9 billion for the acquisition of HST, WHC, MPLXT and the Joint-
Interest Acquisition, $250 million repaymentredeem all of the term loan facility,outstanding Series B preferred units and by $171 million of higher distributions of $49 million to Preferred unitholders, and increased distributions of $188 millionpaid to unitholders and our general partner due mainlyduring the first nine months of 2023 compared to the increase in units outstandingsame period of 2022, as well as a result of the 10 percent increase in our base distribution effective for the distribution per limited partner unit.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 nine months ended September 30, 2023 and September 30, 2022.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | | 2023 | | | 2022 | | 2023 | | 2022 |
Net cash provided by operating activities(1) | | $ | 1,244 | | | | $ | 1,039 | | | $ | 3,908 | | | $ | 3,651 | |
Adjustments to reconcile net cash provided by operating activities to adjusted free cash flow | | | | | | | | | |
Net cash used in investing activities | | (236) | | | | (265) | | | (727) | | | (676) | |
Contributions from MPC | | 7 | | | | 13 | | | 20 | | | 30 | |
| | | | | | | | | |
Distributions to noncontrolling interests | | (11) | | | | (10) | | | (30) | | | (29) | |
Adjusted free cash flow | | 1,004 | | | | 777 | | | 3,171 | | | 2,976 | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
Distributions paid to common and preferred unitholders | | (799) | | | | (755) | | | (2,419) | | | (2,248) | |
Adjusted free cash flow after distributions | | $ | 205 | | | | $ | 22 | | | $ | 752 | | | $ | 728 | |
(1) The three months endedSeptember 30, 2023 and September 30, 2022 include working capital builds of $56 million and $208 million, respectively. The nine months ended September 30, 2023 and September 30, 2022 include a working capital draw of $56 million and a working capital build of $60 million, respectively.
Debt and Liquidity Overview
Our outstanding borrowingsOn 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 September 30, 2017 and December 31, 2016 consisted of the following:
|
| | | | | | | |
(In millions) | September 30, 2017 | | December 31, 2016 |
MPLX LP: | | | |
Bank revolving credit facility due 2022 | $ | 420 |
| | $ | — |
|
Term loan facility due 2019 | — |
| | 250 |
|
5.500% senior notes due February 2023 | 710 |
| | 710 |
|
4.500% senior notes due July 2023 | 989 |
| | 989 |
|
4.875% senior notes due December 2024 | 1,149 |
| | 1,149 |
|
4.000% senior notes due February 2025 | 500 |
| | 500 |
|
4.875% senior notes due June 2025 | 1,189 |
| | 1,189 |
|
4.125% senior notes due March 2027 | 1,250 |
| | — |
|
5.200% senior notes due March 2047 | 1,000 |
| | — |
|
Consolidated subsidiaries: | | | |
MarkWest - 4.500% - 5.500%, due 2023-2025 | 63 |
| | 63 |
|
MPL - capital lease obligations due 2020 | 7 |
| | 8 |
|
Total | 7,277 |
| | 4,858 |
|
Unamortized debt issuance costs | (27 | ) | | (7 | ) |
Unamortized discount | (401 | ) | | (428 | ) |
Amounts due within one year | (1 | ) | | (1 | ) |
Total long-term debt due after one year | $ | 6,848 |
| | $ | 4,422 |
|
The increase in debt as of September 30, 2017 compared to year-end 2016 was duea 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 New2033 Senior Notes in the first quarter of 2017 and from borrowings on the intercompany loan with MPC and the bank revolving credit facility for general partnership purposes including the acquisitions of HST, WHC, MPLXT and the Joint-Interest Acquisition from MPC, the acquisition of our equity interest in MarEn Bakken, the acquisition2053 Senior Notes described above to redeem all of the Ozark pipelineoutstanding Series B preferred units. On March 13, 2023, MPLX used the remaining proceeds from the offering, and capital expenditures. See Notes 3, 4cash on hand, to redeem all of MPLX’s and 14 of the Notes to Consolidated Financial Statements for additional information.
On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0MarkWest’s $1.0 billion five-year bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in July 2022 (“MPLX Credit Agreement 2022”). The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstandingaggregate principal amount of its $250 million term loan with cash on hand.4.50 percent senior notes due July 2023, at par, plus accrued and unpaid interest.
The MPLX Credit Agreement 2022 includes certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type, and that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement 2022) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. As of September 30, 2017, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.4 to 1.0, as well as other covenants contained in the MPLX Credit Agreement 2022. As disclosed in Note 2 of the Notes to Consolidated Financial Statements, we expect the adoption of the lease accounting standards update to result in the recognition of a significant lease obligation. The MPLX Credit Agreement 2022 contains provisions under which the effects of the new accounting standard are not recognized for purposes of financial covenant calculation violations.
Our intention is to maintain an investment gradeinvestment-grade credit profile. As of September 30, 2017,2023, the credit ratings on our senior unsecured debt were at or above investment grade level as follows:
|
| | | | | | | |
Rating Agency | | Rating |
Moody’s | | Baa3Baa2 (stable outlook) |
Standard & Poor’s | | BBB-BBB (stable outlook) |
Fitch | | BBB-BBB (stable outlook) |
The ratings reflect the respective views of the rating agencies.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 MPLX Credit Agreement 2022 doesagreements 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 wouldcould, among other things, increase the applicable interest rates and other fees payable under the MPLX Credit Agreement 2022 and may limit our flexibilityability to obtain future financing.financing, including refinancing existing indebtedness.
Our liquidity totaled $2.1$4.5 billion at September 30, 20172023 consisting of:
| | | | | | | | | | | | | | | | | |
| September 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 | | | | | 960 | |
Total liquidity | | | | | $ | 4,460 | |
|
| | | | | | | | | | | |
| September 30, 2017 |
(In millions) | Total Capacity | | Outstanding Borrowings | | Available Capacity |
MPLX LP - bank revolving credit facility expiring 2022(1) | $ | 2,250 |
| | $ | (423 | ) | | $ | 1,827 |
|
MPC Investment - loan agreement | 500 |
| | (202 | ) | | 298 |
|
Total liquidity | $ | 2,750 |
| | $ | (625 | ) | | $ | 2,125 |
|
Cash and cash equivalents | | | | | 3 |
|
Total liquidity | | | | | $ | 2,128 |
|
(1) Outstanding borrowings include less than $1 million in letters of credit outstanding under this facility.
| |
(1) | Outstanding borrowings include $3 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 agreementsfacilities and issuances of additional debt and equity securities.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, repayment of debt maturities 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.
MPLX’s credit agreement (the “MPLX Credit Agreement”) matures in July 2027 and 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 nine-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, creating liens on assets and entering into transactions with affiliates. As of September 30, 2023, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.4 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.
Equity and Preferred Units Overview
The table below summarizes the changes in the number of units outstanding through September 30, 2017:Unit Repurchase Program
|
| | | | | | | | | | | |
(In units) | Common | | Class B | | General Partner | | Total |
Balance at December 31, 2016 | 357,193,288 |
| | 3,990,878 |
| | 7,371,105 |
| | 368,555,271 |
|
Unit-based compensation awards | 183,509 |
| | — |
| | 3,745 |
| | 187,254 |
|
Issuance of units under the ATM Program | 13,846,998 |
| | — |
| | 282,591 |
| | 14,129,589 |
|
Contribution of HST/WHC/MPLXT | 12,960,376 |
| | — |
| | 264,497 |
| | 13,224,873 |
|
Contribution of the Joint-Interest Acquisition | 18,511,134 |
| | — |
| | 377,778 |
| | 18,888,912 |
|
Class B conversion | 4,350,057 |
| | (3,990,878 | ) | | 7,330 |
| | 366,509 |
|
Balance at September 30, 2017 | 407,045,362 |
| | — |
| | 8,307,046 |
| | 415,352,408 |
|
For more details on equity activity, see Notes 7 and 8 of the Notes to Consolidated Financial Statements.
On July 1, 2017, allAugust 2, 2022, we announced the board authorization for the repurchase of the remaining 3,990,878 Class B units automatically converted into 1.09up to $1.0 billion of MPLX LP 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 the right to receive $6.20 per unit in cash. MPC funded this cash payment, which reduced our liability payable to Class Bamount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.
unitholders by approximately $25 million on July 1, 2017. As a result of the Class BNo units conversion on July 1, 2017, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest. As common units outstanding as of the August 7, 2017 record date, the converted Class B units participated in the second quarter distribution.
The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes including repayment or refinancing of debt and funding for acquisitions, working capital requirements and capital expenditures. Duringwere repurchased during the nine months ended September 30, 2017, the sale of common units under the ATM Program generated net proceeds of approximately $473 million.2023. As of September 30, 2017, $1.7 billion of common units remain available for issuance through the ATM Program2023, we had $846 million remaining under the Distribution Agreement.repurchase authorization.
MPC agreed to waive two-thirdsRedemption of the first quarter 2017 distributionsSeries B Preferred Units
On February 15, 2023, MPLX exercised its right to redeem all 600,000 outstanding 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 commonSeries B preferred units issuedwere payable semi-annually in connection witharrears on the acquisition of HST, WHC and MPLXT. As a result of this waiver, MPC did not receive general partner distributions15th day, or IDRs that would have otherwise accrued on such common units with respect to the first quarter 2017 distributions. The valuebusiness day thereafter, of February and August of each year up to and including February 15, 2023. In accordance with these waived distributions was $6 million. Additionally, in connection with our acquisitionterms, MPLX made a final cash distribution of a partial, indirect equity interest in the Bakken Pipeline system$21 million to Series B preferred unitholders on February 15, 2017, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters beginning2023, in conjunction with the distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated from the acquisition date. Lastly, MPC agreed to waive two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.redemption.
Distributions
We intend to pay at least thea minimum quarterly distribution to the holders of our common units of $0.2625 per unit, or $1.05 per quarter, which equatesunit on an annualized basis, to $109the 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 $436$1,051 million per year, based on the number of common and general partner units outstanding at September 30, 2017. 2023.
On October 25, 2017, we announced the board of directors of our general partner had24, 2023, MPLX declared a cash distribution for the third quarter of $0.58752023, totaling $851 million, or $0.850 per unit thatcommon unit. This distribution will be paid on November 14, 201713, 2023 to common unitholders of record on November 6, 2017. This represents an increase of $0.0250 per unit, or four percent, above the second quarter 2017 distribution of $0.5625 per unit and an increase of 14 percent over the third quarter 2016 distribution. This increase in the distribution is consistent with our intent to maintain an attractive distribution growth profile over an extended period of time.3, 2023. Although our Partnership Agreementpartnership agreement requires that we distribute all of our available cash (as defined in the partnership agreement) 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 quarterly cash distributions to general and limited partners is as follows for the three and nine months ended September 30, 20172023 and 2016. OurSeptember 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 September 30, | | Nine Months Ended September 30, |
(In millions, except per unit data) | 2023 | | 2022 | | 2023 | | 2022 |
Distribution declared: | | | | | | | |
Limited partner units - public | $ | 301 | | | $ | 275 | | | $ | 849 | | | $ | 789 | |
Limited partner units - MPC | 550 | | | 502 | | | 1,554 | | | 1,415 | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
| | | | | | | |
Total LP distribution declared | 851 | | | 777 | | | 2,403 | | | 2,204 | |
Series A preferred units | 25 | | | 23 | | | 71 | | | 65 | |
Series B preferred units(1) | — | | | 10 | | | 5 | | | 31 | |
Total distribution declared | $ | 876 | | | $ | 810 | | | $ | 2,479 | | | $ | 2,300 | |
| | | | | | | |
Quarterly cash distributions declared per limited partner common unit | $ | 0.850 | | | $ | 0.775 | | | $ | 2.400 | | | $ | 2.185 | |
|
| | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 | | 2017 | | 2016 |
Distribution declared: | | | | | | | |
Limited partner units - public | $ | 170 |
| | $ | 135 |
| | $ | 481 |
| | $ | 393 |
|
Limited partner units - MPC | 54 |
| | 44 |
| | 152 |
| | 114 |
|
Limited partner units - GP | 8 |
| | — |
| | 15 |
| | — |
|
General partner units - MPC | 7 |
| | 5 |
| | 18 |
| | 13 |
|
IDRs - MPC | 81 |
| | 49 |
| | 211 |
| | 135 |
|
Total GP & LP distribution declared | 320 |
| | 233 |
| | 877 |
| | 655 |
|
Redeemable preferred units | 16 |
| | 16 |
| | 49 |
| | 25 |
|
Total distribution declared | $ | 336 |
| | $ | 249 |
| | $ | 926 |
| | $ | 680 |
|
| | | | | | | |
Cash distributions declared per limited partner common unit | $ | 0.5875 |
| | $ | 0.5150 |
| | $ | 1.6900 |
| | $ | 1.5300 |
|
Our intentions regarding(1) The nine months ended September 30, 2023 includes the portion of the $21 million distribution growth profile expressed above include forward-looking statements. Such forward-looking statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Factors that could cause actual results to differ materially from those implied in the forward-looking statements include: the adequacy of our capital resources and liquidity, including, but not limitedpaid to the availability of sufficient cash flowSeries B preferred unitholders on February 15, 2023 that was earned during the period prior to pay distributions and execute our business plan; negative capital market conditions, including an increase of the current yield on common units; the timing and extent of changes in commodity prices
redemption.
and demand for natural gas, NGLs, crude oil, feedstocks or refined petroleum products; volatility in and/or degradationTable of market and industry conditions; completion of midstream capacity by our 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 our commercial agreements; our ability to successfully implement our growth plan, whether through organic growth or acquisitions; modifications to earnings and distribution objectives; state and federal environmental, economic, health and safety, energy and other policies and regulations; changes to our capital budget; financial stability of our producer customers and MPC; other risk factors inherent to our industry; and the factors set forth under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2016. In addition, the forward-looking statements included herein could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed here or in our SEC filings could also have material adverse effects on forward-looking statements.Contents
MPC Strategic Actions
On January 3, 2017, MPC announced its plans to offer the Partnership the opportunity to acquire assets contributing an estimated $1.4 billion of annual EBITDA. The Partnership's plans for funding the dropdowns include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In conjunction with the completion of the dropdowns, MPC announced its intentions to offer to exchange its IDRs and two percent GP Interest for common units. Following these transactions, we expect to internally fund a greater portion of our future growth from internal cash flows. The first drop of assets contributing approximately $250 million of annual EBITDA took place in the first quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The second drop of assets contributing approximately $138 million of annual EBITDA took place in the third quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The remaining dropdown, which includes refinery logistics assets and fuels distribution services, with projected annual EBITDA of approximately $1.0 billion has been offered to the Partnership and referred to the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018.
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 maintenancegrowth 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. Examples ofexpenditures 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. In contrast,
MPLX’s initial capital investment plan for 2023 totals $950 million, net of reimbursements, which includes growth capital expenditures are those incurred for acquisitions orof $800 million and maintenance capital improvements that we expect will increase our operating capacity to increase volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of growth$150 million. Growth capital expenditures includeand investments in affiliates during the acquisition of equipment or the construction costs associated with new well connections,nine months ended September 30, 2023 were primarily for gas processing plants and the development or acquisition of additional pipeline, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for us.
Our capital expenditures are showngathering projects in the table below:
|
| | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2017 | | 2016 |
Capital expenditures: | | | |
Maintenance | $ | 59 |
| | $ | 58 |
|
Expansion | 1,002 |
| | 889 |
|
Total capital expenditures | 1,061 |
| | 947 |
|
Less: Increase in capital accruals | 55 |
| | — |
|
Asset retirement expenditures | 2 |
| | 4 |
|
Additions to property, plant and equipment | 1,004 |
| | 943 |
|
Capital expenditures of unconsolidated subsidiaries(1) | 306 |
| | 94 |
|
Total gross capital expenditures | 1,310 |
| | 1,037 |
|
Less: Joint venture partner contributions(2) | 132 |
| | 45 |
|
Total capital expenditures, net | 1,178 |
| | 992 |
|
Less: Maintenance capital | 60 |
| | 58 |
|
Total growth capital | $ | 1,118 |
| | $ | 934 |
|
| |
(1) | Includes amounts related to unconsolidated, Partnership-operated subsidiaries. |
| |
(2) | This represents estimated joint venture partners’ share of growth capital. |
Our organic growth capital plan range has not been revised for the remainder of 2017. We anticipate finishing the year near below the previously reported range. This range excludes acquisition costs for the dropdowns of HST, WHC, MPLXTMarcellus and the Joint-Interest Acquisition, the acquisition of the Ozark pipeline and the MarEn Bakken investment,Permian basins, as discussed in Notes 3 and 4 of the Noteswell as additions to Consolidated Financial Statements. The range also excludes non-affiliated joint venture members’ share of capital expenditures. The G&P segment capital plan includes investments that are expected to support producer customers and complete certain processing plants currently under construction at the Sherwood Complex. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, a butane cavern and a tank farm expansion, and an expansion project to increase line capacity on the Ozark pipeline. We also have large organic growth prospects associated with the anticipated growth of MPC’s operations and third-party activity in our areas of operation that we anticipate will provide attractive returns and cash flows.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:
| | | | | | | | | | | |
| Nine Months Ended September 30, |
(In millions) | 2023 | | 2022 |
Capital expenditures: | | | |
Growth capital expenditures | $ | 555 | | | $ | 451 | |
Growth capital reimbursements(1) | (119) | | | (70) | |
Investments in unconsolidated affiliates | 90 | | | 198 | |
Return of capital | — | | | (11) | |
Capitalized interest | (10) | | | (6) | |
Total growth capital expenditures(2) | 516 | | | 562 | |
Maintenance capital expenditures | 113 | | | 123 | |
Maintenance capital reimbursements | (20) | | | (30) | |
Capitalized interest | (1) | | | (1) | |
Total maintenance capital expenditures | 92 | | | 92 | |
| | | |
Total growth and maintenance capital expenditures | 608 | | | 654 | |
Investments in unconsolidated affiliates(3) | (90) | | | (198) | |
Return of capital | — | | | 11 | |
Growth and maintenance capital reimbursements(4) | 139 | | | 100 | |
Increase in capital accruals | (6) | | | (39) | |
Capitalized interest | 11 | | | 7 | |
Additions to property, plant and equipment(3) | $ | 662 | | | $ | 535 | |
(1) Growth capital reimbursements include reimbursements from customers and our Sponsor.
(2) Total growth capital expenditures exclude $28 million of acquisitions for the nine months ended September 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 September 30, 2017,2023, our contractual cash obligations included long-term debt, capitalfinance and operating lease obligations, purchase obligations for services and to acquire property, plant and equipment, and other liabilities. During the nine months ended September 30, 2017,2023, our long-term debt obligations increased by $4.1 billion$600 million due to the newissuance of senior notes issued and contracts to acquire property, plantuse of proceeds described above in Liquidity and equipment increased $317 million largely due to newCapital Resources-Debt and growing projects.Liquidity Overview. There were no other material changes to theseour contractual obligations outside the ordinary course of business since December 31, 2016.2022.
Off-Balance Sheet Arrangements
As of September 30, 2017, we have not entered into any transactions, agreements or otherOff-balance sheet arrangements comprise those arrangements that would result in off-balance sheet liabilities.
Forward-looking Statements
Our opinions concerningmay potentially impact our liquidity, and capital resources and our abilityresults of operations, even though such arrangements are not recorded as liabilities under GAAP. Our off-balance sheet arrangements are limited to avail ourselvesguarantees that are described in the futureNote 15 of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the globalunaudited consolidated financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital spending. The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include negative capital market conditions, including an increase of the current yield on common units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and transactions discussed herein, including the dropdown from MPC and the proposed exchange of common units for MPC’s economic interests in the general partner, the joint venture with Antero Midstream, the Ozark pipeline acquisition, and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; the inability to agree with respect to the timing of and value attributed to assets identified for dropdown and/or the economic interests in the general partner; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; civil protests and resulting legal/regulatory uncertainty regarding environmental and social issues, including pipeline infrastructure, may prevent or delay the construction and operation of such infrastructure and realization of associated revenues; 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 the Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined products; delays in obtaining necessary third-party approvals and governmental permits; changes in labor, material and equipment costs and availability; planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects; project overruns, disruptions or interruptions of our operations due to the shortage of skilled labor; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response; and other operating and economic considerations. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements. For additional information on forward-looking statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factorsindemnities as disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.2022.
TRANSACTIONS WITH RELATED PARTIESAlthough 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 September 30, 2017,2023, MPC owned our non-economic general partnership interest and held a two percent GP Interest and a 28.4 percent limited partner interest in MPLX LP.
Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 36 percent and 40approximately 65 percent of our total revenues and other income for the third quarter of 2017 and 2016, respectively. outstanding common units.
We provide to MPC with crude oil and product pipeline based on regulated tariff/contracted rates, as well as storage, terminal, fuels distribution, and inland marine transportation services based on regulated tariff rates and storage services and inland marine transportation based on contracted rates.
Of our total costs and expenses, We also have agreements with MPC accountedunder which we receive fees for 22 percent and 25 percentoperating MPC’s retained pipeline assets, providing management services for the third quartermarine business, and operating certain of 2017 and 2016, respectively.MPC’s equity method investments. MPC performedprovides us with certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services.services under employee services and omnibus services agreements.
We believe that transactionsThe below table shows the percentage of Total revenues and other income as well as Total costs and expenses with related parties were conducted under terms comparable to those with unrelated parties. MPC:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended September 30, | | Nine Months Ended September 30, |
| 2023 | | 2022 | | 2023 | | 2022 |
Total revenues and other income(1) | 49 | % | | 46 | % | | 50 | % | | 46 | % |
Total costs and expenses | 29 | % | | 24 | % | | 28 | % | | 24 | % |
(1) 2022 periods exclude gain on sales-type leases.
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, 20162022 and Note 5 of4 to the Notes to Consolidated Financial Statementsunaudited consolidated financial statements in this report.
Environmental Matters and Compliance Costs
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 September 30, 2017, thereenvironmental projects are revised as a result of improved technology or changes in regulatory requirements. There have been no significantmaterial changes to our environmental matters and compliance costs since our Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.2022.
CRITICAL ACCOUNTING ESTIMATESCritical Accounting Estimates
As of September 30, 2017,2023, 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, 2016, as updated by2022.
Accounting Standards Not Yet Adopted
We have not identified any recent accounting pronouncements that are expected to have a material impact on our Current Report on Form 8-K filed on May 1, 2017.
ACCOUNTING STANDARDS NOT YET ADOPTED
Asfinancial condition, results of operations or cash flows upon adoption. Accounting standards are discussed in Note 2 of the Notes to Consolidated Financial Statements, certain newunaudited consolidated financial accounting pronouncements will be effective for our financial statements in the future.statements.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk includesWe are exposed to market risks related to the riskvolatility of loss arising from adversecommodity 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 market rates and prices. We face market risk from commodity price changes and,interest rates. As of September 30, 2023, we did not have any open financial derivative instruments to a lesser extent,hedge the economic risks related to interest rate changesfluctuations; however, we continually monitor the market and non-performance by our customersexposure and counterparties.may enter into these arrangements in the future.
Commodity Price Risk
The information about commodity price risk for the three and nine months ended September 30, 20172023 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, 2016.2022.
Outstanding Derivative Contracts and Sensitivity Analysis
The following tables provideSee Notes 9 and 10 to the unaudited consolidated financial statements for more information onabout the volumefair value measurement of our derivative activityinstruments, 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 related to long liquids price risk at September 30, 2017, including2023 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 September 30, 2023, a 10 percent change in quoted market prices of our derivative instruments, assuming all other factors remain constant, could change the weighted-average prices (“WAVG”):
|
| | | | | | | | | | | |
WTI Crude Swaps | | Volumes (Bbl/d) | | WAVG Price (Per Bbl) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 200 |
| | $ | 54.25 |
| | $ | 42 |
|
|
| | | | | | | | | | | |
Natural Gas Swaps | | Volumes (MMBtu/d) | | WAVG Price (Per MMBtu) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 1,832 |
| | $ | 3.03 |
| | $ | (30 | ) |
2018 | | 2,542 |
| | $ | 2.78 |
| | $ | 4 |
|
|
| | | | | | | | | | | |
Ethane Swaps | | Volumes (Gal/d) | | WAVG Price (Per Gal) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 54,600 |
| | $ | 0.27 |
| | $ | (47 | ) |
|
| | | | | | | | | | | |
Propane Swaps | | Volumes (Gal/d) | | WAVG Price (Per Gal) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 119,932 |
| | $ | 0.61 |
| | $ | (3,164 | ) |
2018 | | 16,925 |
| | $ | 0.64 |
| | $ | (506 | ) |
|
| | | | | | | | | | | |
IsoButane Swaps | | Volumes (Gal/d) | | WAVG Price (Per Gal) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 10,730 |
| | $ | 0.81 |
| | $ | (236 | ) |
2018 | | 1,655 |
| | $ | 0.80 |
| | $ | (38 | ) |
|
| | | | | | | | | | | |
Normal Butane Swaps | | Volumes (Gal/d) | | WAVG Price (Per Gal) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 31,622 |
| | $ | 0.75 |
| | $ | (823 | ) |
2018 | | 4,595 |
| | $ | 0.75 |
| | $ | (120 | ) |
|
| | | | | | | | | | | |
Natural Gasoline Swaps | | Volumes (Gal/d) | | WAVG Price (Per Gal) | | Fair Value (in thousands) |
2017 (Oct - Dec) | | 41,827 |
| | $ | 1.13 |
| | $ | (346 | ) |
2018 | | 3,089 |
| | $ | 1.18 |
| | $ | (20 | ) |
We have a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, we executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential
business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts. The changes in fair value of this embeddedour derivative are based on the difference between the contractualinstruments 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. As of September 30, 2017, the estimated fair value of this contract was a liability of $52Income before income taxes by $1.0 million. This analysis may differ from actual results.
We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of Revenues in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.
Interest Rate Risk and Sensitivity Analysis
Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-termoutstanding third-party debt, excluding capitalfinance 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 September 30, 2017(1) | | Change in Fair Value(2) | | Change in Income Before Income Taxes for the Nine Months Ended September 30, 2017(3) | (In millions) | Fair Value as of September 30, 2023(1) | | Change in Fair Value(2) | | Change in Income Before Income Taxes for the Three Months Ended September 30, 2023(3) |
Long-term debt | | | | | | |
Outstanding debt | | Outstanding debt | | | | | |
Fixed-rate | $ | 7,199 |
| | $ | 575 |
| | N/A |
| Fixed-rate | $ | 17,922 | | | $ | 1,363 | | | N/A |
Variable-rate | $ | 420 |
| | N/A |
| | $ | 2 |
| |
Variable-rate(4) | | Variable-rate(4) | $ | — | | | $ | — | | | $ | — | |
(1) Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.
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(1) | Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities. |
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(2) | Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at September 30, 2017. |
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(3) | Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the nine months ended September 30, 2017. |
(2) Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at September 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 nine months ended September 30, 2023.
(4) MPLX had no outstanding borrowings on the MPLX Credit Agreement as of September 30, 2023.
At September 30, 2017,2023, our portfolio of long-termthird‑party debt consisted of fixed-rate instruments and variable-rate instrumentsoutstanding borrowings, if any, under our term loan facility.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 bank revolving credit or term loan facilities,MPLX Credit Agreement, but may affect our results of operations and cash flows. As of September 30, 2017, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements
See Note 9 in the future.unaudited consolidated financial statements for additional information on the fair value of our debt.
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 13(a)-15(e)13a-15(e) and 15(d)-15(e)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 September 30, 2017,2023, the end of the period covered by this report.
Changes in Internal Control Over Financial Reporting
During the quarter ended September 30, 2017,2023, 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.
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.
Except as described below, 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 quarters ended March 31, 2023 and June 30, 2023.
Dakota Access Pipeline
As previously reported in our Annual Report on Form 10-K for the year ended December 31, 2016,2022, MPLX holds a 9.19 percent indirect interest in July 2015, representatives fromDakota Access, which owns and operates the EPA andBakken Pipeline system. In 2020, the United States Department of Justice conducted a raid on a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United StatesU.S. District Court for the Western District of Pennsylvania. As part of this initiative,Columbia (the “D.D.C.”) ordered the U.S. Attorney’s OfficeArmy Corps of Engineers (“Army Corps”), which granted permits and an easement for the Western District of Pennsylvania proceededBakken 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 Army Corps issued a draft EIS in September 2023 detailing various options for the easement going forward, including denying the easement, approving the easement with an investigation of MarkWest Liberty Midstream’s launcher/receiver, pipelineadditional measures, rerouting the easement, or approving the easement with no changes. The Army Corps has not selected a preferred alternative, but will make a decision in its final review, after considering input from the public and compressor station operations. In responseother agencies. The Army Corps has not provided a definitive date as to when a final decision would be issued.
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 investigation, MarkWest initiated independent studies which demonstratedjoint venture upon certain events occurring to allow the entities that there was no riskown and operate the Bakken Pipeline system to worker safety and no threat of public harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findingssatisfy their senior note payment obligations. The senior notes were supported by a subsequent inspection and reviewissued to repay amounts owed by the Occupational Safetypipeline companies to fund the cost of construction of the Bakken Pipeline system.
If the vacatur of the easement results in a temporary shutdown of the pipeline, MPLX would have to contribute its 9.19 percent pro rata share of funds required to pay interest accruing on the notes and Health Administration. After providing these studies,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 easement and/or return the pipeline into operation. If the vacatur of the easement 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 other substantial documentation related to MarkWest Liberty Midstream's pipelineany accrued and compressor stations, and arranging site visits and conducting several meetings withunpaid interest. As of September 30, 2023, our maximum potential undiscounted payments under the government’s representatives,Contingent Equity Contribution Agreement were approximately $170 million.
Edwardsville Incident
As reported in our Annual Report on September 13, 2016, the U.S. Attorney’s OfficeForm 10-K for the Western District of Pennsylvania rendered a declination decision, dropping its criminal investigation and declining to pursue chargesyear ended December 31, 2022, in this matter.
MarkWest Liberty Midstream continues to discuss with the EPA andMarch 2022, the State of PennsylvaniaIllinois brought an action in Madison County Circuit Court in Illinois against Marathon Pipe Line LLC (“MPL”), an indirect wholly owned subsidiary of MPLX, asserting various violations and demanding a permanent injunction and civil enforcement allegations associated with permitting or other related regulatory obligations for its launcher/receiver and compressor station facilitiespenalties in the region. In connection with these discussions, MarkWest Liberty Midstream received an initial proposala release of crude oil on the Wood River to Patoka 22" line near Edwardsville, Illinois in March 2022. In September 2023, the U.S. Department of Justice and EPA confirmed they will be pursuing federal enforcement for alleged Clean Water Act violations arising from this incident as well as other pipeline releases. We cannot currently estimate the EPA to settle allamount of any civil claims associated withpenalty or the timing of the resolution of this matter for the combinationbut do not believe any civil penalty will have a material impact on our consolidated results of a proposedoperations, financial position or cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream has submitted a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis and were not the subject of regulation and consequently that the settlement proposal is excessive. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.flows.
Item 1A. Risk Factors
We are subject to various risks and uncertainties inThere have been no material changes from the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factorsrisk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.2022.
Item 2. Unregistered Sales of Equity Securities
In connection with the issuance of 14,887 common units upon the vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan, 359,179 common units as a result of the conversion of Class B units to common units and 1,184,335 common units under the ATM Program, our general partner purchased an aggregate of 31,803 general partner units for $1,059,390.81 in cash during the three months ended September 30, 2017, to maintain its two percent general partner interest in us. The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
On September 1, 2017, in connection with the Joint-Interest Acquisition, we issued 377,778 general partner units to our general partner. The number of general partner units issued were calculated by dividing $12,600,000 by 33.3529, the simple average of the ten day trading volume weighted average NYSE price of an MPLX LP common unit for the ten trading days ending at market close on August 31, 2017. The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.
Item 5. Other Information
Amended Restricted Stock Award Agreement
On October 26, 2017, C. Corwin Bromley entered into an Amended Restricted Stock Award Agreement with MPC (the “Amended Award Agreement”) to provide forDuring the immediate vesting of a restricted stock award upon Mr. Bromley’s retirement effective January 1, 2018, which was announced by MPLX LP (the “Partnership”) on August 4, 2017. Mr. Bromley was a named executive officer in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.
The foregoing description of the Amended Award Agreement is summary in nature and subject to, and qualified in its entirety by, the full text of the Amended Award Agreement, a copy of which is attached as Exhibit 10.2 to this Quarterly Report on Form 10-Q for the quarterly periodquarter ended September 30, 2017 and is incorporated herein by reference.
MPLX LP Executive Change in Control Severance Benefits Plan
Effective October 26, 2017, the board of directors of Marathon Petroleum Corporation (the “Corporation”) and the board of directors of MPLX GP LLC, the general partner (the “General Partner”) of MPLX LP (“the Partnership”), adopted the MPLX LP Executive Change in Control Severance Benefits Plan (the “MPLX Plan”).
The purpose of the MPLX Plan is to recognize the contributions of the senior executives who provide services to the Corporation2023, no director or the Partnership and to assure the continued provision of services by these senior executives. The MPLX Plan is intended to operate as a companion plan to the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan (the “MPC Plan”). It is intended that the MPLX Plan shall not result in a duplication of benefits in the event a participant would be eligible to receive benefits under both the MPLX Plan and the MPC Plan. The following is a summary of the MPLX Plan:
The MPLX Plan applies to certain senior executives who provide services to the Partnership, the Corporation or any of their respective subsidiaries or affiliates.
A participant is generally entitled to receive benefits under the MPLX Plan if within two years following a Partnership Change in Controlofficer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of MPLX Plan), the participant’s employmentadopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement” (as each term is terminated without cause or for good reason, with good reason generally being defined in the MPLX Plan as a reduction in the participant’s roles, responsibilities, pay or benefits or the participant is required to relocate more than 50 miles from his or her current location. However, benefits are not payable if the termination is for cause or due to mandatory retirement, death, disability or resignation (other than for good reason) by the participant.Item 408 of Regulation S-K).
In addition to any earned but unpaid salary, a lump sum cash amount equal to the value of the participant’s unused vacation days and any normal post-termination compensation and benefits under the retirement, insurance and other compensation and benefit plans in which the participant participates, upon a Partnership Change in Control and Qualified Termination (as defined in the MPLX Plan), participants are eligible to receive: (i) a cash payment equal to three times the sum of the participant’s base salary and the highest bonus paid in the three years before the Qualified Termination or, if higher, in the three years before the Partnership Change in Control; (ii) life and health insurance benefits for up to 36 months after termination at the active employee cost; (iii) benefits that are equivalent to the retiree medical and life benefit provided under the MPC Plan; and (iv) a cash payment that is equivalent to the supplemental retirement benefit and supplemental savings benefit provided under the MPC Plan.
Participants who incur a Qualified Termination or who separate from service with all of the Partnership, the General Partner and any applicable buyer or successor entity within two years after the Partnership Change in Control under circumstances that would have resulted in a Qualified Termination had such separation occurred at the time of the Partnership Change in Control and participants who remain in service with the Corporation (and its affiliates) following the Partnership Change in Control may become eligible for the following benefits: (i) all Partnership equity awards that vest based solely upon the passage of time will be become vested and exercisable; and (ii) all Partnership equity awards that vest based on the attainment of performance goals will become vested as to the entire award with payment as follows (a) with respect to the period prior to the Partnership Change in Control (“Pre-CiC Period”), the award will be determined using actual performance during the Pre-CiC Period; and (b) with respect to the period after the Partnership Change in Control, the award will be determined assuming performance goals were satisfied at target levels. Participants who incur a Qualified Termination and participants who remain in or commence services with the Partnership, General Partner or any applicable buyer or successor entity (or any of their affiliates) following the Partnership Change in Control are eligible for the following benefits: (i) all Corporation equity awards will become vested and exercisable; (ii) the vesting of any Corporation equity awards that otherwise would vest based on the attainment of performance goals shall remain subject to the attainment of applicable performance goals at the end of the regularly scheduled performance period.
The Corporation and the General Partner may at any time amend or terminate the MPLX Plan, provided that, for a period of two years following a Partnership Change in Control, the MPLX Plan may not be amended in a manner adverse to a participant with respect to that Partnership Change in Control. Any amendment or termination shall be set out in an instrument in writing and executed by an appropriate officer.
The foregoing description of the MPLX Plan is summary in nature and subject to, and qualified in its entirety by, the full text of the MPLX Plan, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 and is incorporated herein by reference.
Item 6. Exhibits
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| | | | 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 | | |
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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| | | | Incorporated by Reference | | | | |
Exhibit Number | | Exhibit Description | | Form | | Exhibit | | Filing Date | | SEC File No. | | Filed Herewith | | Furnished Herewith |
| | | | 8-K | | 2.1 |
| | 9/1/2017 | | 001-35714 | | | | |
| | | | S-1 | | 3.1 |
| | 7/2/2012 | | 333-182500 | | | | |
| | | | S-1/A | | 3.2 |
| | 10/9/2012 | | 333-182500 | | | | |
| | | | 10-Q | | 3.3 |
| | 10/31/2016 | | 001-35714 | | | | |
| | | | 10-K | | 3.4 |
| | 2/24/2017 | | 001-35714 | | | | |
| | Credit Agreement, dated as of July 21, 2017, among MPLX LP, as borrower, Wells Fargo Bank, National Association, as administrative agent, each of Wells Fargo Securities, LLC, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and RBC Capital Markets, as joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, N.A., as syndication agent, each of Bank of America, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Royal Bank of Canada, as documentation agents, and the other lenders and issuing banks that are parties thereto. | | 8-K | | 10.1 |
| | 7/27/2017 | | 001-35714 | | | | |
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| | | | Incorporated by Reference | | | | |
Exhibit
Number
| | Exhibit Description | | Form | | Exhibit | | Filing Date | | SEC File No. | | Filed
Herewith
| | Furnished
Herewith
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| | | | | | | | | | | | | | X |
| | | | | | | | | | | | | | X |
101.INS | | XBRL Instance Document | | | | | | | | | | X | | |
101.SCH | | XBRL Taxonomy Extension Schema | | | | | | | | | | X | | |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase | | | | | | | | | | X | | |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase | | | | | | | | | | X | | |
101.LAB | | XBRL Taxonomy Extension Label Linkbase | | | | | | | | | | X | | |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase | | | | | | | | | | X | | |
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.
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| MPLX LP | | |
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| MPLX LPBy: | | |
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| By: | | MPLX GP LLC |
| | | Its general partner |
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Date: October 30, 201731, 2023 | By: | | /s/ Paula L. Rosson
Kelly D. Wright |
| | | Paula L. RossonKelly D. Wright |
| | | Senior Vice President and Chief Accounting OfficerController of MPLX GP LLC
(the (the general partner of MPLX LP)
|