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Delaware
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001-35666
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45-5200503
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(State or other jurisdiction
of incorporation)
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(Commission
File Number)
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(IRS Employer
Identification No.)
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| ☐ |
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
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| ☐ |
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
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| ☐ |
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
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| ☐ |
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))
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Title of each class
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Trading
Symbol(s)
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Name of each exchange
on which registered
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Common Units
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SMLP
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New York Stock Exchange
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Item 8.01
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Other Events.
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| • |
Item 6. Selected Financial Data;
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| • |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations;
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| • |
Item 8. Financial Statements and Supplementary Data; and
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| • |
Exhibit 21.1 List of Subsidiaries.
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| • |
Item 1. Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements; and
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| • |
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
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Item 9.01
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Financial Statements and Exhibits.
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| 99.3 | Updated 2019 Annual Report on Form 10-K - Item 8. Financial Statements and Supplementary Data. | |||
| 99.4 | Updated 2020 Quarterly Report on Form 10-Q - Item 1. Financial Statements and Notes to Unaudited Condensed Consolidated Financial Statements. | |||
| 99.5 | Updated 2020 Quarterly Report on Form 10-Q - Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations. | |||
| 101.INS |
*
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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 |
*
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Inline XBRL Taxonomy Extension Schema | ||
| 101.CAL |
*
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Inline XBRL Taxonomy Extension Calculation Linkbase | ||
| 101.DEF |
*
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Inline XBRL Taxonomy Extension Definition Linkbase | ||
| 101.LAB |
*
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Inline XBRL Taxonomy Extension Label Linkbase | ||
| 101.PRE |
*
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Inline XBRL Taxonomy Extension Presentation Linkbase | ||
| 104 | Cover Page Interactive Data File – the cover page XBRL tags are embedded within the Inline XBRL document | |||
| * |
Pursuant to Rule 406T of Regulation
S-T,
the Interactive Data Files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections. The financial information contained in the XBRL(eXtensible Business Reporting Language)-related documents is unaudited and unreviewed.
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Summit Midstream Partners, LP
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| (Registrant) | ||||||
| By: Summit Midstream GP, LLC (its general partner) | ||||||
| Dated: August 7, 2020 |
/s/ Marc D. Stratton
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|||||
| Marc D. Stratton, Executive Vice President and Chief Financial Officer | ||||||
EXHIBIT 21.1
SUMMIT MIDSTREAM PARTNERS, LP
LIST OF SUBSIDIARIES
|
Name |
State or other jurisdiction of incorporation or organization |
|
|
Bison Midstream, LLC |
Delaware |
|
|
DFW Midstream Services LLC |
Delaware |
|
|
Epping Transmission Company, LLC |
Delaware |
|
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Grand River Gathering, LLC |
Delaware |
|
|
Meadowlark Midstream Company, LLC |
Delaware |
|
|
Mountaineer Midstream Company, LLC |
Delaware |
|
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Polar Midstream, LLC |
Delaware |
|
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Red Rock Gathering Company, LLC |
Delaware |
|
|
Summit Contribution Holdings, LLC |
Delaware |
|
|
Summit Management Holdings, LLC |
Delaware |
|
|
Summit Midstream Finance Corp. |
Delaware |
|
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Summit Midstream GP, LLC |
Delaware |
|
|
Summit Midstream Holdings, LLC |
Delaware |
|
|
Summit Midstream Marketing, LLC |
Delaware |
|
|
Summit Midstream Niobrara, LLC |
Delaware |
|
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Summit Midstream OpCo, LP |
Delaware |
|
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Summit Midstream Partners Holdings, LLC |
Delaware |
|
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Summit Midstream Partners, LLC |
Delaware |
|
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Summit Midstream Permian Finance, LLC |
Delaware |
|
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Summit Midstream Permian II, LLC |
Delaware |
|
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Summit Midstream Permian, LLC |
Delaware |
|
|
Summit Midstream Utica, LLC |
Delaware |
|
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Summit Operating Services Company, LLC |
Delaware |
|
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Summit Permian Transmission Holdco, LLC |
Delaware |
|
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Summit Permian Transmission, LLC |
Delaware |
EX 21.1-1
EXHIBIT 23.1
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-234781 on Form S-3 and Registration Statement Nos. 333-184214, 333-189684 and 333-237323 on Form S-8 of our report dated March 9, 2020 (August 7, 2020 as to the retrospective adjustments to the financial statements for the common control transaction described in Notes 1 and 19), relating to the financial statements of Summit Midstream Partners, LP appearing in this Current Report on Form 8-K dated August 7, 2020.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
August 7, 2020
EX 23.1-1
EXHIBIT 99.1
EXPLANATORY NOTE
On May 28, 2020, Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), closed on a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”
The May 2020 acquisition of Summit Investments was a transaction between entities under common control. As a result, the Partnership recast its financial statements for the period that the entities were under common control by Summit Investments to retrospectively reflect the May 2020 acquisition. Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP Buy-In Transaction are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.
The information in this Item 6. Selected Financial Data includes periods prior to the GP Buy-In Transaction. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.
EX 99.1-1
Item 6. Selected Financial Data.
The selected consolidated financial data presented as of and for the years ended December 31, 2019, 2018, 2017, 2016 and 2015 have been derived from the audited consolidated financial statements of SMLP, as recasted to reflect the retrospective recast of SMLP’s financial statements resulting from the GP Buy-In Transaction. The following selected financial data should be read in conjunction with Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 8, “Financial Statements and Supplementary Data” of this Current Report on Form 8-K.
The following table presents selected balance sheet and other data as of the date indicated.
| December 31, | ||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| (In thousands, except per-unit amounts) | ||||||||||||||||||||
|
Balance sheet data: |
||||||||||||||||||||
|
Total assets |
$ | 2,574,098 | $ | 3,033,219 | $ | 2,907,719 | $ | 3,120,405 | $ | 3,174,917 | ||||||||||
|
Total long-term debt |
1,627,825 | 1,478,780 | 1,319,808 | 1,240,301 | 1,267,270 | |||||||||||||||
|
Mandatorily redeemable 11.00% Class C preferred units |
— | — | — | 99,526 | 156,857 | |||||||||||||||
|
Mezzanine capital |
27,450 | — | — | — | — | |||||||||||||||
|
Partners’ capital |
785,236 | 1,391,567 | 1,497,260 | 1,635,420 | 1,595,354 | |||||||||||||||
|
Other data: |
||||||||||||||||||||
|
Market price per common unit |
$ | 3.31 | $ | 10.05 | $ | 20.50 | $ | 25.15 | $ | 18.73 | ||||||||||
The following table presents selected statements of operations and cash flows as well as other financial data for the annual periods indicated.
| Year ended December 31, | ||||||||||||||||||||
| 2019 | 2018 | 2017 | 2016 | 2015 | ||||||||||||||||
| (In thousands, except per-unit amounts) | ||||||||||||||||||||
|
Statements of operations data: |
||||||||||||||||||||
|
Total revenues |
$ | 443,528 | $ | 506,653 | $ | 488,741 | $ | 402,362 | $ | 400,282 | ||||||||||
|
Total costs and expenses (1) |
406,657 | 378,079 | 512,486 | 293,156 | 561,087 | |||||||||||||||
|
Interest expense |
91,966 | 82,830 | 88,701 | 78,596 | 75,358 | |||||||||||||||
|
Early extinguishment of debt |
— | — | 22,039 | — | — | |||||||||||||||
|
Loss from equity method investees (2) |
(337,851 | ) | (10,888 | ) | (2,223 | ) | (30,344 | ) | (6,563 | ) | ||||||||||
|
Net (loss) income |
(393,726 | ) | 34,320 | (136,914 | ) | (1,402 | ) | (243,071 | ) | |||||||||||
|
(Loss) earnings per limited partner unit: |
||||||||||||||||||||
|
Common unit - basic |
$ | (4.70 | ) | $ | 0.07 | $ | (4.13 | ) | $ | 0.55 | $ | (1.44 | ) | |||||||
|
Common unit - diluted |
(4.70 | ) | 0.07 | (4.13 | ) | 0.54 | (1.44 | ) | ||||||||||||
|
Subordinated unit - basic and diluted (3) |
(2.88 | ) | ||||||||||||||||||
|
Statements of cash flows data: |
||||||||||||||||||||
|
Capital expenditures (other than acquisition capital expenditures) |
$ | 182,291 | $ | 200,586 | $ | 124,215 | $ | 142,942 | $ | 274,119 | ||||||||||
|
Contributions to equity method investees |
— | 4,924 | 25,513 | 31,582 | 86,200 | |||||||||||||||
|
Investment in equity method investee |
18,316 | — | — | — | — | |||||||||||||||
|
Other financial data: |
||||||||||||||||||||
|
Distributions declared per unit (4) |
$ | 1.438 | $ | 2.300 | $ | 2.300 | $ | 2.300 | $ | 2.270 | ||||||||||
| (1) |
Includes (i) long-lived asset impairments of $60.5 million in 2019, (ii) a goodwill impairment of $16.2 million in 2019, (iii) long-lived asset impairments of $3.9 million in 2018, (iv) long-lived asset impairments of $101.9 million and contract intangible asset impairments of $85.2 million in 2017, and (v) goodwill impairments of $248.9 million and environmental remediation expenses of $21.8 million in 2015. See Notes 5, 6, 7 and 16 to the consolidated financial statements. |
| (2) |
Includes (i) an impairment of our equity method investment in OGC of $329.7 million and an impairment in OCC of $6.3 million in 2019 and (ii) our 40% share, or $5.7 million and $1.4 million in asset impairments recognized by Ohio Gathering in December 2018 and 2017. In addition, 2018 includes our 40% share, or $2.0 million, of an estimated legal contingency. See Note 8 to the consolidated financial statements. |
EX 99.1-2
| (3) |
The subordination period ended on February 16, 2016 and all 24,409,850 subordinated units converted to common units on a one-for-one basis. |
| (4) |
Represents distributions declared in a given period by the publicly traded master limited partnership, Summit Midstream Partners, LP, to its unitholders prior to the GP Buy-In Transaction. For example, for the year ended December 31, 2019, represents the distributions paid in February 2019, in May 2019, in August 2019 and in November 2019. |
The preceding tables should be read in conjunction with MD&A and the consolidated financial statements and notes thereto.
EX 99.1-3
EXHIBIT 99.2
EXPLANATORY NOTE
On May 28, 2020, Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), closed on a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”
The May 2020 acquisition of Summit Investments was a transaction between entities under common control. As a result, the Partnership recast its financial statements for the period that the entities were under common control by Summit Investments to retrospectively reflect the May 2020 acquisition. Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP Buy-In Transaction presented below are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.
The information in this Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes periods prior to the GP Buy-In Transaction. Consequently, the Partnership’s consolidated financial statements have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.
EX 99.2-1
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the consolidated financial statements and notes thereto included in this report. Among other things, the consolidated financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements. You should read the following discussion and analysis of financial condition and results of operations in conjunction with the financial statements, and the notes thereto, included in Item 8, “Financial Statements and Supplementary Data” of this Current Report on Form 8-K.
This MD&A comprises the following sections:
| • |
Overview |
| • |
Trends and Outlook |
| • |
How We Evaluate Our Operations |
| • |
Results of Operations |
| • |
Liquidity and Capital Resources |
| • |
Critical Accounting Estimates |
| • |
Forward-Looking Statements |
Overview
We are a value-driven limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.
We classify our midstream energy infrastructure assets into two categories:
| • |
Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas. |
| • |
Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas. |
EX 99.2-2
We are the owner-operator of or have significant ownership interests in the following gathering and transportation systems, which comprise our Core Focus Areas:
| • |
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; |
| • |
Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; |
| • |
Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
| • |
Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
| • |
Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming; |
| • |
Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; and |
| • |
Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. |
We are the owner-operator of the following gathering systems, which comprise our Legacy Areas:
| • |
Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; |
| • |
DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and |
| • |
Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. |
For additional information on our organization and systems, see Notes 1 and 4 to the consolidated financial statements.
Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the year ended December 31, 2019, these additional activities accounted for approximately 20% of total revenues including marketing transactions, and approximately 14% of total revenues excluding marketing transactions.
We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.
EX 99.2-3
The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” section herein.
| Year ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| (In thousands) | ||||||||||||
|
Net (loss) income |
$ | (393,726 | ) | $ | 34,320 | $ | (136,914 | ) | ||||
|
Reportable segment adjusted EBITDA |
||||||||||||
|
Utica Shale |
$ | 29,292 | $ | 30,285 | $ | 34,011 | ||||||
|
Ohio Gathering |
39,126 | 39,969 | 41,246 | |||||||||
|
Williston Basin |
69,437 | 76,701 | 66,413 | |||||||||
|
DJ Basin |
18,668 | 7,558 | 6,624 | |||||||||
|
Permian Basin |
(879 | ) | (1,200 | ) | — | |||||||
|
Piceance Basin |
98,765 | 111,042 | 111,113 | |||||||||
|
Barnett Shale |
43,043 | 43,268 | 46,232 | |||||||||
|
Marcellus Shale |
20,051 | 24,267 | 23,888 | |||||||||
|
Net cash provided by operating activities |
$ | 161,741 | $ | 206,230 | $ | 213,048 | ||||||
|
Capital expenditures (1) |
182,291 | 200,586 | 124,215 | |||||||||
|
Contributions to equity method investees |
— | 4,924 | 25,513 | |||||||||
|
Investment in equity method investee |
18,316 | — | — | |||||||||
|
Distributions to noncontrolling interest SMLP unitholders |
$ | 68,874 | $ | 109,101 | $ | 107,598 | ||||||
|
Distributions to Series A Preferred unitholders |
28,500 | 28,500 | 2,375 | |||||||||
|
Distributions to Energy Capital Partners |
120,730 | 11,800 | 301,672 | |||||||||
|
Issuance of senior notes |
— | — | 500,000 | |||||||||
|
Tender and redemption of senior notes |
— | — | (300,000 | ) | ||||||||
|
Net borrowings (repayments) under Revolving Credit Facility |
211,000 | 205,000 | (387,000 | ) | ||||||||
|
Issuance of SMP Holdings term loan |
— | — | 300,000 | |||||||||
|
Repayments under SMP Holdings term loan |
(65,250 | ) | (49,250 | ) | (24,000 | ) | ||||||
|
Proceeds from issuance of Series A preferred units, net of costs (2) |
27,392 | — | 293,238 | |||||||||
|
Proceeds from ATM Program common unit issuances, net of costs |
— | — | 17,078 | |||||||||
| (1) |
See “Liquidity and Capital Resources” herein and Note 4 to the consolidated financial statements for additional information on capital expenditures. |
| (2) |
Reflects proceeds from the issuance of Series A preferred units. |
Year ended December 31, 2019. The following items are reflected in our financial results:
| • |
In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. We completed an other-than-temporary impairment analysis to determine the potential equity method impairment charge to be recorded on our consolidated financial statements. As a result, an impairment charge of approximately $329.7 million was recorded in the loss from equity method investees caption on the consolidated statement of operations. |
| • |
In September 2019, in connection with our annual impairment evaluation, we determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value and we recognized a goodwill impairment charge of $16.2 million. |
EX 99.2-4
| • |
In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de-commissioned and we recorded an impairment charge of $10.2 million related to these assets. |
| • |
In December 2019, as part of our financing for the Double E Project, we formed Permian Holdco, a newly created, unrestricted subsidiary of SMLP that indirectly owns SMLP’s 70% interest in Double E. In connection with the formation of Permian Holdco, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) on December 24, 2019 to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.4 million. |
| • |
In June 2019, we continued development of the Double E Project after securing firm 10-year commitments under binding precedent agreements for a substantial majority of the pipeline’s initial throughput capacity of 1.35 Bcf of gas per day and executing the JV Agreement with an affiliate of Double E’s foundation shipper. The Double E Project, which consists of an approximately 116-mile mainline and related facilities, will provide interstate natural gas transportation service from the Delaware Basin production area to the Waha Hub in Texas. Double E filed its application under Section 7(c) of the NGA with the FERC on July 31, 2019 to obtain a certificate of public convenience and necessity authorizing the construction and operation of the pipeline. |
In connection with the Double E Project, Summit Permian Transmission contributed total assets of approximately $23.6 million for a 70% ownership interest in Double E. Concurrent with this contribution, Double E distributed $7.3 million to the Partnership. We expect to own at least a 50% interest in the Double E Project, will lead the development, permitting and construction of the Double E Project and will operate the pipeline upon commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the FERC certificate) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021.
| • |
In December 2019, Red Rock Gathering and certain affiliates of SMLP (collectively, “the Red Rock Parties”) entered into a Purchase and Sale Agreement (the “Red Rock PSA”) pursuant to which the Red Rock Parties agreed to sell certain Red Rock Gathering system assets for a cash purchase price of $12.0 million (the “Red Rock Sale”). Prior to closing, we recorded an impairment charge of $14.2 million based on the expected consideration and the carrying value for the Red Rock Gathering system assets. On December 2, 2019, we closed the Red Rock Sale. The impairment is included in the Long-lived asset impairment caption on the consolidated statement of operations. The financial contribution of these assets (a component of the Piceance Basin reportable segment) are included in our consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019. |
| • |
Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system in the Williston Basin. On March 22, 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our consolidated financial statements and footnotes for the historical periods through March 22, 2019. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream. |
EX 99.2-5
| • |
In the third quarter of 2019, we began an internal initiative to evaluate and transform our cost structure, enhance margins and improve our competitive position in response to a weakening commodity price backdrop. For the year ended December 31, 2019, we incurred approximately $5.0 million in restructuring costs relating to this initiative (included in general and administrative expense). |
Year ended December 31, 2018. The following items are reflected in our financial results:
| • |
Increased natural gas, NGLs and condensate sales and cost of natural gas and NGLs associated with increased marketing related activities. |
| • |
During the year ended December 31, 2018, we recognized $6.0 million in gathering services and related fees from MVC shortfall adjustments. Under Topic 606, we recognize customer obligations under their MVCs as revenue and contract assets when (i) we consider it remote that the customer will utilize shortfall payments to offset gathering or processing fees in excess of its MVCs in subsequent periods; (ii) the customer incurs a shortfall in a contract with no banking mechanism or claw back provision; (iii) the customer’s banking mechanism has expired; or (iv) it is remote that the customer will use its unexercised right. |
| • |
In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $3.9 million. |
Year ended December 31, 2017. The following items are reflected in our financial results:
| • |
In February 2017, we completed a public offering of $500.0 million principal amount of 5.75% Senior Notes. Concurrent with and following the offering, we initiated a tender offer for the outstanding 7.5% Senior Notes. All remaining 7.5% Senior Notes were redeemed on March 18, 2017, with payment made on March 20, 2017. We used the proceeds from the issuance of the 5.75% Senior Notes to (i) fund the repurchase of the outstanding $300.0 million principal amount of 7.5% Senior Notes, (ii) pay redemption and call premiums on the 7.5% Senior Notes totaling $17.9 million and (iii) pay $172.0 million of the balance outstanding under our Revolving Credit Facility. |
| • |
In March 2017, we closed on a $300.0 million senior secured term loan facility, (the “Term Loan B”) with the maturity date of May 15, 2022. Borrowings under the Term Loan B bear interest at LIBOR plus 6.00% or ABR plus 5.00%, as defined in the Term Loan B Facility. We used the net proceeds of the Term Loan B to redeem the Class C Redemption Units and to make a distribution to the Sponsor. |
| • |
In March 2017, we recognized $37.7 million of gathering services and related fees revenue that had been previously deferred, and recorded on our consolidated balance sheet as deferred revenue, in connection with an MVC arrangement with a certain Williston Basin customer, for which we determined we had no further performance obligations. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, the Williston Basin segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer. |
| • |
In November 2017, we issued 300,000 Series A Preferred Units representing limited partner interests in the Partnership at a price of $1,000 per unit. We used the net proceeds of $293.2 million to repay outstanding borrowings under our Revolving Credit Facility. |
| • |
In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain intangible and long-lived assets related to the Bison Midstream system in the Williston Basin were not fully recoverable and we recorded an impairment charge of $187.1 million. |
EX 99.2-6
Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
| • |
Natural gas, NGL and crude oil supply and demand dynamics; |
| • |
Production from U.S. shale plays; |
| • |
Capital markets availability and cost of capital; and |
| • |
Shifts in operating costs and inflation. |
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.
Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. The average spot price of natural gas decreased by approximately 19% from 2018 to 2019, primarily due to natural gas supply exceeding demand. The average daily Henry Hub Natural Gas Spot Price was $2.56 per MMBtu during 2019, compared with $3.15 per MMBtu during 2018. Henry Hub closed at $2.09 per MMBtu on December 31, 2019 and as of February 10, 2020, closed at $1.85 per MMBtu. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and an elevated level of natural gas in storage in the continental United States. The average amount of working natural gas in underground storage in the continental U.S. was 2.47 Tcf in 2019, which was 9.5% higher than in 2018. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. However, we note that over the last several years there has been an increasing societal opposition to the production of hydrocarbons generally, which may be reflected in legislation, executive orders or regulations that may significantly restrict the domestic production of fossil fuels, including natural gas.
In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Crude oil prices decreased in 2019, with the average daily Cushing, Oklahoma West Texas Intermediate (“WTI”) crude oil spot price decreasing from an average $65.23 per barrel during 2018 to an average of $56.98 per barrel during 2019, representing a 12.6% decrease, reflecting broader market concerns for global oil supply and demand dynamics. In response to the general decrease in crude oil prices, the number of active crude oil drilling rigs in the continental United States decreased from 885 in December 2018 to 677 in December 2019, according to Baker Hughes. Over the next several years, we expect that crude oil prices will support continued drilling activity and increasing production in the Williston Basin, Permian Basin and, given the current regulatory environment in Colorado, in rural parts of the DJ Basin.
Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance, Barnett, Bakken, Marcellus, Utica and Permian Basin shale plays in which we operate, and we believe that these long-term capital investments will support drilling activity in unconventional shale plays over the long term.
Rate of growth in production from U.S. shale plays. Some of our producer customers have adjusted their drilling and completion activities and schedules to manage drilling and completion costs at levels that are achievable using internally generated cash flow from their underlying operations. Historically, as part of a strategy to accelerate production growth, these producers would raise external capital to fund drilling and completion costs in excess of the cash flows generated
EX 99.2-7
from their underlying assets. In general, we expect our producer customers to reduce completion and production activities across many of our systems relative to our previous expectations as a result of a weakening commodity price environment and a continuation of the general trend of producers constraining drilling and completion activity to levels that can be satisfied with internally generated cash flow.
Capital markets availability and cost of capital. Credit markets were volatile throughout 2019, as borrowing costs increased and investors assessed the impact of rising rates on broader economic activity. Capital markets conditions, including but not limited to availability and higher borrowing costs, could affect our ability to access the debt capital markets to the extent necessary, to fund our future growth. Furthermore, market demand for equity issued by master limited partnerships has been significantly lower in recent years than it has been historically, which may make it more challenging for us to finance our capital expenditures with the issuance of additional equity. We recently announced a reduction in our common unit distribution to $0.125 per quarter, beginning with the distribution paid in respect of the fourth quarter of 2019, and this reduction may further reduce demand for our common units. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly.
Shifts in operating costs and inflation. Throughout most of the last five years, high levels of crude oil and natural gas exploration, development and production activities across the United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services. While we expect lower service-related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas.
EX 99.2-8
How We Evaluate Our Operations
We conduct and report our operations in the midstream energy industry through eight reportable segments:
| • |
the Utica Shale, which is served by Summit Utica; |
| • |
Ohio Gathering, which includes our ownership interest in OGC and OCC; |
| • |
the Williston Basin, which is served by Polar and Divide and Bison Midstream; |
| • |
the DJ Basin, which is served by Niobrara G&P; |
| • |
the Permian Basin, which is served by Summit Permian; |
| • |
the Piceance Basin, which is served by Grand River; |
| • |
the Barnett Shale, which is served by DFW Midstream; and |
| • |
the Marcellus Shale, which is served by Mountaineer Midstream. |
Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream.
Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 4 to the consolidated financial statements).
Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include:
| • |
throughput volume; |
| • |
revenues; |
| • |
operation and maintenance expenses; and |
| • |
segment adjusted EBITDA. |
Throughput Volume
The volume of (i) natural gas that we gather, compress, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.
As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new supplies of throughput is impacted by:
| • |
successful drilling activity within our AMIs; |
| • |
the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected; |
| • |
the number of new pad sites in our AMIs awaiting connections; |
| • |
our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing AMIs; and |
| • |
our ability to gather, treat and/or process production that has been released from commitments with our competitors. |
EX 99.2-9
We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day.
Revenues
Our revenues are primarily attributable to the volumes that we gather, compress, treat and/or process and the rates we charge for those services. A majority of our gathering and processing agreements are fee-based, which limits our direct exposure to fluctuations in commodity prices. We also have percent-of-proceeds arrangements with certain customers under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.
Certain of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs help us generate stable revenues and serve to mitigate the financial impact associated with declining volumes.
Operation and Maintenance Expenses
We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.
Segment Adjusted EBITDA
Segment adjusted EBITDA is a supplemental financial measure used by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.
Segment adjusted EBITDA is used to assess:
| • |
the ability of our assets to generate cash sufficient to make cash distributions and support our indebtedness; |
| • |
the financial performance of our assets without regard to financing methods, capital structure or historical cost basis; |
| • |
our operating performance and return on capital as compared to other companies in the midstream energy sector, without regard to financing or capital structure; |
| • |
the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities; and |
| • |
the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitment shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items. |
Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the consolidated financial statements. For information on pending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the consolidated financial statements.
EX 99.2-10
Results of Operations
Our financial results are recognized as follows:
Gathering services and related fees. Revenue earned from the gathering, compression, treating and processing services that we provide to our customers.
Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) natural gas and crude oil marketing services in and around our gathering systems, (iii) the sale of natural gas we retain from certain DFW Midstream customers and (iv) the sale of condensate we retain from our gathering services at Grand River.
Other revenues. Revenue earned primarily from (i) certain costs for which certain of our customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system.
Cost of natural gas and NGLs. The cost of natural gas and NGLs represents (i) the purchase of natural gas and NGLs associated with marketing activity surrounding certain of our natural gas and crude oil-related operations and (ii) the costs associated with the percent-of-proceeds arrangements under which we sell natural gas and NGLs purchased from certain of our customers on the Bison Midstream and Grand River systems.
Operation and maintenance. Operation and maintenance primarily comprises direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services. These items represent the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of variations in throughput volumes but may fluctuate depending on the activities performed during a specific period.
General and administrative. Expenses associated with our operations that are not specifically associated with the operation and maintenance of a particular system or another cost and expense line item. These expenses largely reflect salaries, benefits and incentive compensation, professional fees, insurance and rent.
Depreciation and amortization. The depreciation of our property, plant and equipment and the amortization of our contract and right-of-way intangible assets.
Transaction costs. Financial and legal advisory costs associated with completed acquisitions and divestitures and restructuring activities.
Other income or expense. Generally represents other items of gain or loss but may also include interest income.
Interest expense. Interest expense associated with our Revolving Credit Facility, Term Loan B and our Senior Notes as well as amortization expense associated with debt issuance costs.
Income tax expense or benefit. Represents the expense or benefit associated with the Texas Margin Tax.
Income or loss from equity method investees. Represents the income or loss and other-than-temporary impairment associated with our ownership interest in Ohio Gathering.
EX 99.2-11
Consolidated Overview for the Years Ended December 31, 2019, 2018 and 2017
The following table presents certain consolidated data and volume throughput for the years ended December 31.
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 326,747 | $ | 344,616 | $ | 394,427 | (5 | %) | (13 | %) | ||||||||||
|
Natural gas, NGLs and condensate sales |
86,994 | 134,834 | 68,459 | (35 | %) | 97 | % | |||||||||||||
|
Other revenues |
29,787 | 27,203 | 25,855 | 9 | % | 5 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
443,528 | 506,653 | 488,741 | (12 | %) | 4 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
63,438 | 107,661 | 57,237 | (41 | %) | 88 | % | |||||||||||||
|
Operation and maintenance |
98,719 | 100,978 | 93,882 | (2 | %) | 8 | % | |||||||||||||
|
General and administrative |
55,947 | 54,991 | 56,351 | 2 | % | (2 | %) | |||||||||||||
|
Depreciation and amortization |
110,354 | 107,263 | 115,737 | 3 | % | (7 | %) | |||||||||||||
|
Transaction costs |
3,017 | — | 50 | * | * | |||||||||||||||
|
(Gain) loss on asset sales, net |
(1,536 | ) | — | 527 | * | * | ||||||||||||||
|
Long-lived asset impairment |
60,507 | 7,186 | 188,702 | * | (96 | %) | ||||||||||||||
|
Goodwill impairment |
16,211 | — | — | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
406,657 | 378,079 | 512,486 | 8 | % | (26 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Other income (expense) |
451 | (169 | ) | 298 | * | * | ||||||||||||||
|
Interest expense |
(91,966 | ) | (82,830 | ) | (88,701 | ) | 11 | % | (7 | %) | ||||||||||
|
Early extinguishment of debt |
— | — | (22,039 | ) | * | * | ||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
(Loss) income before income taxes and loss from equity method investees |
(54,644 | ) | 45,575 | (134,187 | ) | * | * | |||||||||||||
|
Income tax expense |
(1,231 | ) | (367 | ) | (504 | ) | * | * | ||||||||||||
|
Loss from equity method investees |
(337,851 | ) | (10,888 | ) | (2,223 | ) | * | * | ||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Net (loss) income |
$ | (393,726 | ) | $ | 34,320 | $ | (136,914 | ) | * | * | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Volume throughput (1): |
||||||||||||||||||||
|
Aggregate average daily throughput - natural gas (MMcf/d) |
1,397 | 1,673 | 1,748 | (16 | %) | (4 | %) | |||||||||||||
|
Aggregate average daily throughput - liquids (Mbbl/d) |
105.3 | 94.9 | 75.2 | 11 | % | 26 | % | |||||||||||||
| * |
Not considered meaningful |
| (1) |
Exclusive of volume throughput for Ohio Gathering. For additional information, see the “Ohio Gathering” section herein. |
EX 99.2-12
Volumes – Gas. Natural gas throughput volumes decreased 276 MMcf/d for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting:
| • |
a volume throughput decrease of 111 MMcf/d for the Marcellus Shale segment. |
| • |
a volume throughput decrease of 99 MMcf/d for the Piceance Basin segment. |
| • |
a volume throughput decrease of 86 MMcf/d for the Utica Shale segment. |
| • |
a volume throughput increase of 18 MMcf/d for the Permian Basin segment. |
| • |
a volume throughput increase of 10 MMcf/d for the DJ Basin segment. |
Natural gas throughput volumes decreased 75 MMcf/d for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflected:
| • |
a volume throughput decrease of 31 MMcf/d for the Piceance Basin segment. |
| • |
a volume throughput decrease of 28 MMcf/d for the Marcellus Shale segment. |
| • |
a volume throughput decrease of 14 MMcf/d for the Barnett Shale segment. |
| • |
a volume throughput decrease of 6 MMcf/d for the Utica Shale segment. |
| • |
a volume throughput increase of 4 MMcf/d for the DJ Basin segment. |
Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment increased 10.4 Mbbl/d for the year ended December 31, 2019 compared to the year ended December 31, 2018.
Crude oil and produced water throughput volumes at the Williston segment increased 19.7 Mbbl/d for the year ended December 31, 2018 compared to the year ended December 31, 2017.
For additional information on volumes, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” section herein.
Revenues. Total revenues decreased $63.1 million during the year ended December 31, 2019 compared to the prior year primarily comprised of a $47.8 million decrease in natural gas, NGLs and condensate sales and a $17.9 million decrease in gathering services and related fees.
Gathering Services and Related Fees. Gathering services and related fees decreased $17.9 million compared to the year ended December 31, 2018, primarily reflecting:
| • |
a $11.2 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting $5.1 million in lower MVC shortfall revenue attributable to the timing of revenue recognition and an unfavorable gathering rate mix on certain gathering services and related fees. Also impacting 2019 revenues was the presentation of $4.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations. |
| • |
a $14.5 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines. |
| • |
a $5.1 million decrease in gathering services and related fees in the Marcellus Shale relating to lower volume throughput due to natural production declines partially offset by additional drilling and completion activities. |
| • |
a $3.3 million decrease in gathering services and related fees in the Utica Shale due to a combination of natural production declines on existing wells together with increased temporary production curtailments associated with infill drilling, completion activity and other operational downtime partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019 and a more favorable volume and gathering rate mix from customers. |
EX 99.2-13
| • |
a $2.0 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $9.8 million decrease in gathering services and related fees attributable to the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019. This was partially offset by higher liquids volume throughput due to increased drilling and completion activity. |
| • |
a $10.7 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines. |
| • |
a $3.5 million increase in gathering services and related fees in the Permian Basin (commissioned in the fourth quarter of 2018). |
Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $47.8 million compared to the year ended December 31, 2018, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $44.2 million decrease in natural gas, NGL and condensate purchases.
Total revenues for the year ended December 31, 2018 increased $17.9 million compared to the year ended December 31, 2017 primarily comprised of a $66.4 million increase in natural gas, NGLs and condensate sales and a $49.8 million decrease in gathering services and related fees.
Gathering Services and Related Fees. Gathering services and related fees decreased $49.8 million compared to the year ended December 31, 2017, as compared to the prior year, primarily reflecting:
| • |
the impact of the 2017 recognition of $37.7 million of previously deferred revenue related to a certain Williston Basin customer. |
| • |
a $13.3 million decrease in gathering services and related fees for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements currently recognized on a net basis in cost of natural gas and NGLs under Topic 606. |
| • |
a $3.6 million decrease in gathering services and related fees for the Barnett Shale segment largely as a result of the expiration of an MVC during 2017. |
| • |
a $6.0 million increase from the recognition of MVC shortfall adjustments for the Barnett Shale segment under Topic 606 (see Note 3 in the consolidated financial statements). |
Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales increased $66.4 million compared to the year ended December 31, 2017, primarily reflecting the addition of natural gas, NGL and crude oil marketing services provided for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments.
Costs and Expenses. Total costs and expenses increased $28.6 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily reflecting:
| • |
the recognition of $34.9 million of certain long-lived asset impairments in the DJ Basin. |
| • |
a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale. |
| • |
the recognition of $14.2 million of long-lived asset impairments relating to the sale of certain Red Rock Gathering system assets in the Piceance Basin. |
| • |
the recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale. |
| • |
the recognition of $1.3 million of certain long-lived asset impairments in the Permian Basin. |
| • |
a $44.2 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity. |
EX 99.2-14
Total costs and expenses decreased $134.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting:
| • |
the impact of the 2017 recognition of $187.1 million of certain intangible and long-lived asset impairments relating to the Bison Midstream system in the Williston Basin segment. |
| • |
a $63.7 million increase in natural gas, NGLs and condensate purchases primarily driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments. |
| • |
a $7.1 million increase in operation and maintenance expense primarily due to a $3.1 million increase in planned compressor overhaul maintenance and a $4.0 million increase in remediation expenses. |
| • |
a $13.3 million decrease in the cost of natural gas and NGLs for the Williston Basin segment due to the reclassification of amounts under certain percent-of-proceeds arrangements under Topic 606 that were previously recognized in gathering services and related fees. |
| • |
a $8.5 million decrease in depreciation and amortization primarily due to the impairment of certain intangible and long-lived assets relating to the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017. |
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $44.2 million during the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily driven by lower natural gas, NGL and crude oil marketing activity.
Cost of natural gas and NGLs increased $50.4 million during the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting:
| • |
a $63.7 million increase in natural gas, NGLs, crude oil and condensate purchases driven by increased natural gas, NGL and crude oil marketing activity for the Piceance Basin, DJ Basin, Barnett Shale and Williston Basin segments. |
| • |
the reclassification of $13.3 million in cost of natural gas and NGLs for the Williston Basin segment under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees, which is presented net in cost of natural gas and NGLs under Topic 606. |
Operation and Maintenance. Operation and maintenance expense decreased $2.3 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.
Operation and maintenance expense increased $7.1 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to a $3.1 million increase in planned compressor overhaul maintenance and a $4.0 million increase in remediation expenses.
General and Administrative. General and administrative expense increased $1.0 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to a $7.5 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation.
General and administrative expense decreased $1.4 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily reflecting a decrease in information technology expense of $1.3 million and an increase in capitalized labor of $0.7 million associated with the continued development of Summit Permian and the DJ Basin. For additional information, see the “Corporate and Other Overview of the Years Ended December 31, 2019, 2018 and 2017” sections herein.
Depreciation and Amortization. The increase in depreciation and amortization expense during 2019 compared to the year ended December 31, 2018 was primarily due to the assets placed into service in the Permian Basin. The decrease in depreciation and amortization expense during 2018 compared to the year ended December 31, 2017 was primarily due to the impairment of certain intangible and long-lived assets on the Bison Midstream system in the Williston Basin segment recognized in the fourth quarter of 2017.
EX 99.2-15
Transaction Costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $2.1 million in financial advisory costs associated with restructuring the equity of certain subsidiaries in 2019.
Interest Expense. The increase in interest expense in the year ended December 31, 2019 compared to the year ended December 31, 2018, was primarily due to a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.
The decrease in interest expense in 2018 compared to the year ended December 31, 2017, was as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility, (iii) a lower average outstanding balance on the Revolving Credit Facility and (iv) a lower outstanding balance on the Term Loan B. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility.
Early Extinguishment of Debt. The early extinguishment of debt recognized during the year ended December 31, 2017 was driven by the tender and redemption of the $300.0 million principal 7.5% Senior Notes.
For additional information, see the “Segment Overview for the Years Ended December 31, 2019, 2018 and 2017” and “Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017” sections herein and “Business – Recent Developments.”
Segment Overview for the Years Ended December 31, 2019, 2018 and 2017
Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.
| Utica Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Average daily throughput (MMcf/d) |
273 | 359 | 365 | (24 | %) | (2 | %) | |||||||||||||
Volume throughput declined compared to the year ended December 31, 2018 due to natural production declines from existing wells on pad sites connected to the Summit Utica, partially offset by the completion of new wells at the end of the fourth quarter of 2018 and throughout 2019. In addition, volume throughput was impacted by an increase in temporary production curtailments associated with infill drilling, completion activity and other operational downtime associated with customers on existing pad sites.
Volume throughput decreased during 2018 due to natural declines from existing wells on pad sites connected to the Summit Utica system together with temporary production curtailments associated with infill drilling and completion activity from customers on existing pad sites, partially offset by the completion of new wells during 2017 and in 2018. In addition, the TPL-7 connector project was commissioned in the first quarter of 2017 which partially offset volume declines in 2018 due to a full year of operations.
EX 99.2-16
Financial data for our Utica Shale reportable segment follows.
| Utica Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 31,926 | $ | 35,233 | $ | 38,907 | (9 | %) | (9 | %) | ||||||||||
|
Other revenues |
2,065 | — | — | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
33,991 | 35,233 | 38,907 | (4 | %) | (9 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Operation and maintenance |
4,151 | 4,556 | 4,487 | (9 | %) | 2 | % | |||||||||||||
|
General and administrative |
530 | 374 | 409 | 42 | % | (9 | %) | |||||||||||||
|
Depreciation and amortization |
7,659 | 7,672 | 7,009 | (0 | %) | 9 | % | |||||||||||||
|
Loss on asset sales, net |
— | 5 | 542 | * | * | |||||||||||||||
|
Long-lived asset impairment |
— | 1,440 | 878 | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
12,340 | 14,047 | 13,325 | (12 | %) | 5 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
7,659 | 7,672 | 7,009 | |||||||||||||||||
|
Adjustments related to capital reimbursement activity |
(18 | ) | (18 | ) | — | |||||||||||||||
|
Loss on asset sales, net |
— | 5 | 542 | |||||||||||||||||
|
Long-lived asset impairment |
— | 1,440 | 878 | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 29,292 | $ | 30,285 | $ | 34,011 | (3 | %) | (11 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
Year ended December 31, 2019. Segment adjusted EBITDA decreased $1.0 million compared to the year ended December 31, 2018, primarily reflecting:
| • |
a $3.3 million decrease in gathering services and related fees due to the volume throughput declines discussed above partially offset by a more favorable volume and gathering rate mix from customers. |
| • |
a $2.1 million increase in other revenues due to the release of an acreage dedication to one of our customers. |
Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.7 million compared to the year ended December 31, 2017, primarily reflecting:
| • |
a $3.7 million decrease in gathering services and related fees from a lower gathering rate mix associated with increasing volumes from the TPL-7 connector project, which was commissioned in the first quarter of 2017, along with a decrease in volume throughput from wells that we gather from pad sites on the Summit Utica system and temporary production curtailments. The decrease was partially offset by an increase in volume throughput associated with new wells completed in 2017 and 2018. |
Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. We recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period.
Gross volume throughput for Ohio Gathering, based on a one-month lag follows.
| Ohio Gathering | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Average daily throughput (MMcf/d) |
732 | 769 | 766 | (5 | %) | * | ||||||||||||||
| * |
Not considered meaningful |
Volume throughput for the Ohio Gathering system in 2019 decreased compared to the year ended December 31, 2018 as a result of natural production declines on existing wells on the system, partially offset by the completion of new wells.
EX 99.2-17
Volume throughput for the Ohio Gathering system in 2018 increased slightly compared to the year ended December 31, 2017 as a result of increased drilling activity from our customers during the second half of 2017 and in 2018, partially offset by natural production declines on existing wells on the system.
Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.
| Ohio Gathering | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Proportional adjusted EBITDA for equity method investees |
$ | 39,126 | $ | 39,969 | $ | 41,246 | (2 | %) | (3 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 39,126 | $ | 39,969 | $ | 41,246 | (2 | %) | (3 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
Year ended December 31, 2019. Segment adjusted EBITDA for equity method investees decreased $0.8 million compared to the year ended December 31, 2018.
Other items to note:
| • |
In the fourth quarter of 2019, we impaired our equity method investment in Ohio Gathering (see Note 8 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019. |
Year ended December 31, 2018. Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the year ended December 31, 2017, primarily as a result of higher expenses, partially offset by higher volumes at OGC and OCC.
Williston Basin. The Polar and Divide, Tioga Midstream (through March 22, 2019; refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream) and Bison Midstream systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.
| Williston Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Aggregate average daily throughput - natural gas (MMcf/d) |
12 | 18 | 19 | (33 | %) | (5 | %) | |||||||||||||
|
Aggregate average daily throughput - liquids (Mbbl/d) |
105.3 | 94.9 | 75.2 | 11 | % | 26 | % | |||||||||||||
Natural gas. Natural gas volume throughput in 2019 decreased compared to the year ended December 31, 2018, primarily reflecting natural production declines, the sale of Tioga Midstream and operational downtime on the Bison Midstream system. Natural gas volume throughput in 2018 decreased compared to the year ended December 31, 2017, primarily reflecting natural production declines.
Liquids. The increase in liquids volume throughput in 2019 compared to the year ended December 31, 2018, primarily reflected well drilling and completion activity by existing customers on our Polar and Divide system in 2018 and in 2019 as well as the addition of a new customer, partially offset by the sale of Tioga Midstream and natural production declines.
The increase in liquids volume throughput in 2018 compared to the year ended December 31, 2017 primarily reflected well completion activity by existing customers on our Polar and Divide system in the second half of 2017 and in 2018 as well as the addition of new customers.
EX 99.2-18
Financial data for our Williston Basin reportable segment follows.
| Williston Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 77,626 | $ | 79,606 | $ | 120,717 | (2 | %) | (34 | %) | ||||||||||
|
Natural gas, NGLs and condensate sales |
16,461 | 31,840 | 29,724 | (48 | %) | 7 | % | |||||||||||||
|
Other revenues |
11,564 | 12,204 | 11,062 | (5 | %) | 10 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
105,651 | 123,650 | 161,503 | (15 | %) | (23 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
5,821 | 18,284 | 30,004 | (68 | %) | (39 | %) | |||||||||||||
|
Operation and maintenance |
27,172 | 25,300 | 25,058 | 7 | % | 1 | % | |||||||||||||
|
General and administrative |
1,493 | 2,089 | 2,335 | (29 | %) | (11 | %) | |||||||||||||
|
Depreciation and amortization |
19,829 | 22,642 | 33,772 | (12 | %) | (33 | %) | |||||||||||||
|
(Gain) loss on asset sales, net |
(1,177 | ) | 63 | (22 | ) | * | * | |||||||||||||
|
Long-lived asset impairment |
10 | 3,972 | 187,127 | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
53,148 | 72,350 | 278,274 | (27 | %) | * | ||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
19,829 | 22,642 | 33,772 | |||||||||||||||||
|
Adjustments related to MVC shortfall payments |
— | — | (37,693 | ) | ||||||||||||||||
|
Adjustments related to capital reimbursement activity |
(1,728 | ) | (1,276 | ) | — | |||||||||||||||
|
(Gain) loss on asset sales, net |
(1,177 | ) | 63 | (22 | ) | |||||||||||||||
|
Long-lived asset impairment |
10 | 3,972 | 187,127 | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 69,437 | $ | 76,701 | $ | 66,413 | (9 | %) | 15 | % | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
Year ended December 31, 2019. Segment adjusted EBITDA decreased $7.3 million compared to the year ended December 31, 2018 primarily reflecting:
| • |
a decrease of $7.6 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the year ended December 31, 2018 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput primarily reflecting natural production declines and operational downtime on the Bison Midstream system. The operational downtime began with third party maintenance on infrastructure located downstream of the Bison Midstream system, which created an operational disruption on the Bison Midstream system for approximately 15 days during the second quarter and continued to impact throughput capacity through August 2019. This was partially offset by higher liquids volume throughput on our Polar and Divide system due to increased drilling and completion activity in 2018 and throughout 2019. |
| • |
a $1.9 million increase in operation and maintenance expense primarily related to an increase in environmental remediation costs. |
Other items to note:
| • |
On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our consolidated financial statements for the period from January 1, 2019 through March 22, 2019. |
EX 99.2-19
Year ended December 31, 2018. Segment adjusted EBITDA increased $10.3 million compared to the year ended December 31, 2017, primarily reflecting an increase in liquids volume throughput on our Polar and Divide system and $1.6 million in fees attributable to our Dakota Access Pipeline interconnect which was commissioned in the second quarter of 2017.
Other items to note:
| • |
The decrease in the cost of natural gas and NGLs includes a $13.3 million reduction in expense due to the reclassification of amounts under certain percent-of-proceeds arrangements previously recognized in gathering services and related fees under Topic 606 (see Note 3 in the consolidated financial statements). |
| • |
In the fourth quarter of 2018, we impaired certain long-lived assets relating to the Tioga Midstream system in the Williston Basin (see Note 5 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2018. |
| • |
Depreciation and amortization decreased during 2018 largely as a result of the long-lived asset impairment recognized in 2017. |
DJ Basin. The Niobrara G&P system provides midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.
| DJ Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Average daily throughput (MMcf/d) |
27 | 17 | 13 | 59 | % | 31 | % | |||||||||||||
Volume throughput in 2019 increased compared to the year ended December 31, 2018, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.
Volume throughput in 2018 increased compared to the year ended December 31, 2017, primarily as a result of ongoing drilling and completion activity across our service area.
Financial data for our DJ Basin reportable segment follows.
| DJ Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 21,940 | $ | 11,251 | $ | 8,918 | 95 | % | 26 | % | ||||||||||
|
Natural gas, NGLs and condensate sales |
389 | 371 | 398 | 5 | % | (7 | %) | |||||||||||||
|
Other revenues |
3,721 | 3,672 | 2,544 | 1 | % | 44 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
26,050 | 15,294 | 11,860 | 70 | % | 29 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
34 | 45 | 17 | (24 | %) | 165 | % | |||||||||||||
|
Operation and maintenance |
7,616 | 6,482 | 5,001 | 17 | % | 30 | % | |||||||||||||
|
General and administrative |
315 | 647 | 218 | (51 | %) | 197 | % | |||||||||||||
|
Depreciation and amortization |
3,732 | 3,133 | 2,636 | 19 | % | 19 | % | |||||||||||||
|
Loss on asset sales |
— | — | 3 | * | * | |||||||||||||||
|
Long-lived asset impairment |
34,913 | 9 | — | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
46,610 | 10,316 | 7,875 | 352 | % | 31 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
3,732 | 3,133 | 2,636 | |||||||||||||||||
|
Adjustments related to capital reimbursement activity |
583 | (562 | ) | — | ||||||||||||||||
|
Loss on asset sales |
— | — | 3 | |||||||||||||||||
|
Long-lived asset impairment |
34,913 | 9 | — | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 18,668 | $ | 7,558 | $ | 6,624 | 147 | % | 14 | % | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
EX 99.2-20
Year ended December 31, 2019. Segment adjusted EBITDA increased $11.1 million compared to the year ended December 31, 2018, primarily reflecting:
| • |
a $10.7 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity, a more favorable volume and gathering rate mix from customers, and the commissioning of our new natural gas processing plant in June 2019. This was partially offset by natural production declines. |
| • |
a $1.1 million increase in operation and maintenance expense primarily due to higher costs to support volume growth. |
Other items to note:
| • |
During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019. |
Year ended December 31, 2018. Segment adjusted EBITDA increased $0.9 million compared to the year ended December 31, 2017, primarily reflecting:
| • |
an increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity. |
| • |
a $1.5 million increase in operation and maintenance expense primarily due to $1.1 million of higher electricity expenses we pass through to certain customers (which is also included in the increase in Other revenues in the table above) in addition to higher operation and maintenance costs to support volume growth. |
Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.
| Permian Basin | ||||||||||||
| Year ended December 31, |
Percentage
Change |
|||||||||||
| 2019 | 2018 | 2019 v. 2018 | ||||||||||
|
Average daily throughput (MMcf/d) |
19 | 1 | * | |||||||||
EX 99.2-21
Financial data for our Permian Basin reportable segment follows.
| Permian Basin | ||||||||||||
| Year ended December 31, |
Percentage
Change |
|||||||||||
| 2019 | 2018 | 2019 v. 2018 | ||||||||||
| (In thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 3,610 | $ | 115 | * | |||||||
|
Natural gas, NGLs and condensate sales |
16,383 | 843 | * | |||||||||
|
Other revenues |
310 | — | * | |||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
20,303 | 958 | * | |||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
15,113 | 1,569 | * | |||||||||
|
Operation and maintenance |
5,755 | 428 | * | |||||||||
|
General and administrative |
314 | 161 | * | |||||||||
|
Depreciation and amortization |
4,868 | 243 | * | |||||||||
|
Gain on asset sales, net |
(148 | ) | — | * | ||||||||
|
Long-lived asset impairment |
1,327 | 761 | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
27,229 | 3,162 | * | |||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
4,868 | 243 | ||||||||||
|
Gain on asset sales, net |
(148 | ) | — | |||||||||
|
Long-lived asset impairment |
1,327 | 761 | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | (879 | ) | $ | (1,200 | ) | * | |||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Year ended December 31, 2019. Segment adjusted EBITDA totaled ($0.9) million primarily reflecting fixed operating costs associated with commissioning and operating the Lane processing plant and certain inefficiencies and higher fuel costs associated with lower plant utilization and initial production volumes.
Other items to note:
In December 2019, we impaired certain long-lived assets in the Permian Basin (see Notes 5 and 6 to the consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2019.
Year ended December 31, 2018. Segment adjusted EBITDA totaled ($1.2) million primarily reflecting less than one month’s volume throughput of the Summit Permian natural gas gathering and processing system commissioned in December 2018 as well as operational and general and administrative expenses incurred during the year.
Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.
| Piceance Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Aggregate average daily throughput (MMcf/d) |
452 | 551 | 582 | (18 | %) | (5 | %) | |||||||||||||
EX 99.2-22
Volume throughput decreased compared to the year ended December 31, 2018, as a result of natural production declines.
Volume throughput decreased compared to the year ended December 31, 2017, as a result of natural production declines, partially offset by drilling and completion activity that occurred across our service area during the second half of 2017 and through the third quarter of 2018.
Financial data for our Piceance Basin reportable segment follows.
| Piceance Basin | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 121,357 | $ | 135,810 | $ | 136,834 | (11 | %) | (1 | %) | ||||||||||
|
Natural gas, NGLs and condensate sales |
7,954 | 14,800 | 13,452 | (46 | %) | 10 | % | |||||||||||||
|
Other revenues |
4,327 | 4,909 | 4,607 | (12 | %) | 7 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
133,638 | 155,519 | 154,893 | (14 | %) | 0 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
5,612 | 9,591 | 7,952 | (41 | %) | 21 | % | |||||||||||||
|
Operation and maintenance |
27,306 | 33,947 | 30,143 | (20 | %) | 13 | % | |||||||||||||
|
General and administrative |
1,009 | 1,168 | 2,617 | (14 | %) | (55 | %) | |||||||||||||
|
Depreciation and amortization |
47,018 | 46,919 | 46,289 | * | 1 | % | ||||||||||||||
|
Loss on asset sales, net |
104 | — | — | * | * | |||||||||||||||
|
Long-lived asset impairment |
14,162 | 1,004 | 697 | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
95,211 | 92,629 | 87,698 | 3 | % | 6 | % | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
47,018 | 46,919 | 46,289 | |||||||||||||||||
|
Adjustments related to MVC shortfall payments |
(103 | ) | 10 | (3,068 | ) | |||||||||||||||
|
Adjustments related to capital reimbursement activity |
(843 | ) | 219 | — | ||||||||||||||||
|
Loss on asset sales, net |
104 | — | — | |||||||||||||||||
|
Long-lived asset impairment |
14,162 | 1,004 | 697 | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 98,765 | $ | 111,042 | $ | 111,113 | (11 | %) | (0 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
Year ended December 31, 2019. Segment adjusted EBITDA decreased $12.3 million compared to the year ended December 31, 2018, primarily reflecting:
| • |
a $14.5 million decrease in gathering services and related fees as a result of natural production declines. |
| • |
a $2.9 million decrease in natural gas, NGLs and condensate activity (sales and purchases) as a result of lower volume throughput and lower commodity prices associated with the sale of NGLs and condensate. |
| • |
a $6.6 million decrease in operation and maintenance expense primarily due to a $3.3 million reduction in planned compressor overhaul maintenance costs and $2.2 million in lower compensation expense. |
Other items to note:
| • |
In December 2019, we sold certain assets from our Red Rock Gathering system and recorded an impairment charge of $14.2 million based on the difference between the consideration received and the then carrying value of the assets at closing. The noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. |
EX 99.2-23
Year ended December 31, 2018. Segment adjusted EBITDA decreased $0.1 million compared to the year ended December 31, 2017, primarily reflecting:
| • |
a $3.8 million increase in operation and maintenance expense primarily due to planned compressor overhaul maintenance costs during the period. |
| • |
a $1.5 million decrease in general and administrative expenses. |
| • |
a $2.3 million increase, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees primarily as a result of the drilling and completion activity that occurred across our service area by other customers during the second half of 2017 and through the third quarter of 2018, and a $1.0 million MVC shortfall payment received from a customer in 2018 that did not occur in 2017, partially offset by natural production declines. |
Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment.
Volume throughput for our Barnett Shale reportable segment follows.
| Barnett Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Average daily throughput (MMcf/d) |
251 | 253 | 267 | (1 | %) | (5 | %) | |||||||||||||
Volume throughput decreased slightly compared to the year ended December 31, 2018 reflecting natural production declines partially offset by new volumes from well completion activity throughout 2019.
Volume throughput declined compared to the year ended December 31, 2017 reflecting natural production declines, partially offset by new volumes from completion activity during the fourth quarter of 2017, first quarter of 2018 and the fourth quarter of 2018.
Financial data for our Barnett Shale reportable segment follows.
| Barnett Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 47,862 | $ | 59,030 | $ | 61,622 | (19 | %) | (4 | %) | ||||||||||
|
Natural gas, NGLs and condensate sales |
17,147 | 2,523 | 1,946 | 580 | % | 30 | % | |||||||||||||
|
Other revenues (1) |
6,793 | 6,712 | 8,099 | 1 | % | (17 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
71,802 | 68,265 | 71,667 | 5 | % | (5 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
10,751 | — | — | * | * | |||||||||||||||
|
Operation and maintenance |
21,729 | 21,358 | 23,074 | 2 | % | (7 | %) | |||||||||||||
|
General and administrative |
968 | 971 | 1,146 | (0 | %) | (15 | %) | |||||||||||||
|
Depreciation and amortization |
15,354 | 15,658 | 15,604 | (2 | %) | 0 | % | |||||||||||||
|
(Gain) loss on asset sales, net |
(325 | ) | (68 | ) | 4 | * | * | |||||||||||||
|
Long-lived asset impairment |
10,095 | — | — | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
58,572 | 37,919 | 39,828 | 54 | % | (5 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
16,575 | 15,325 | 15,001 | |||||||||||||||||
|
Adjustments related to MVC shortfall payments |
3,579 | (3,642 | ) | (612 | ) | |||||||||||||||
|
Adjustments related to capital reimbursement activity |
(111 | ) | 1,307 | — | ||||||||||||||||
|
(Gain) loss on asset sales, net |
(325 | ) | (68 | ) | 4 | |||||||||||||||
|
Long-lived asset impairment |
10,095 | — | — | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 43,043 | $ | 43,268 | $ | 46,232 | (1 | %) | (6 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
| (1) |
Includes the amortization expense associated with our favorable and unfavorable gas gathering contracts as reported in other revenues. |
EX 99.2-24
Year ended December 31, 2019. Segment adjusted EBITDA decreased $0.2 million compared to the year ended December 31, 2018.
Other items to note:
| • |
Impacting 2019 revenues was the presentation of $4.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations. |
| • |
In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. |
Year ended December 31, 2018. Segment adjusted EBITDA decreased $3.0 million compared to the year ended December 31, 2017, primarily reflecting:
| • |
a $4.3 million decrease, after taking into account the adjustments related to MVC shortfall payments and adjustments related to capital reimbursement activity, in gathering services and related fees associated with the expiration of MVCs during 2017 of $3.6 million in addition to lower volume throughput. |
| • |
a $1.7 million decrease in operation and maintenance expense primarily from $1.3 million of lower electricity expenses associated with lower volume throughput and a decrease in tax expenses. |
Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment.
Volume throughput for the Marcellus Shale reportable segment follows.
| Marcellus Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
|
Average daily throughput (MMcf/d) |
363 | 474 | 502 | (23 | %) | (6 | %) | |||||||||||||
Volume throughput decreased compared to the year ended December 31, 2018, primarily due to natural production declines partially offset by additional drilling and completion activities.
Volume throughput decreased compared to the year ended December 31, 2017, primarily due to natural production declines. These declines were partially offset by volumes generated by the completion, in the second half of 2017 and first quarter of 2018, of a number of drilled but uncompleted (“DUC”) wells.
EX 99.2-25
Financial data for our Marcellus Shale reportable segment follows.
| Marcellus Shale | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Gathering services and related fees |
$ | 24,471 | $ | 29,573 | $ | 30,394 | (17 | %) | (3 | %) | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total revenues |
24,471 | 29,573 | 30,394 | (17 | %) | (3 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Operation and maintenance |
3,861 | 4,813 | 6,057 | (20 | %) | (21 | %) | |||||||||||||
|
General and administrative |
521 | 397 | 449 | 31 | % | (12 | %) | |||||||||||||
|
Depreciation and amortization |
9,141 | 9,090 | 9,047 | 1 | % | 0 | % | |||||||||||||
|
Goodwill impairment |
16,211 | — | — | * | * | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Total costs and expenses |
29,734 | 14,300 | 15,553 | 108 | % | (8 | %) | |||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Add: |
||||||||||||||||||||
|
Depreciation and amortization |
9,141 | 9,090 | 9,047 | |||||||||||||||||
|
Goodwill impairment |
16,211 | — | — | |||||||||||||||||
|
Adjustments related to capital reimbursement activity |
(38 | ) | (96 | ) | — | |||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||
|
Segment adjusted EBITDA |
$ | 20,051 | $ | 24,267 | $ | 23,888 | (17 | %) | 2 | % | ||||||||||
|
|
|
|
|
|
|
|||||||||||||||
| * |
Not considered meaningful |
Year ended December 31, 2019. Segment adjusted EBITDA decreased $4.2 million compared to the year ended December 31, 2018, primarily reflecting:
| • |
a $5.1 million decrease in gathering services and related fees as a result of volume declines partially offset by additional drilling and completion activities. |
| • |
a $1.0 million decrease in operation and maintenance expense primarily due to a decrease in various operating expenses. |
Other items to note:
| • |
In September 2019, we recorded a goodwill impairment charge of $16.2 million relating to the Mountaineer Midstream system in the Marcellus Shale (see Note 7 to the consolidated financial statements). This noncash impairment expense had no impact on segment adjusted EBITDA for the year ended December 31, 2019. |
EX 99.2-26
Year ended December 31, 2018. Segment adjusted EBITDA increased $0.4 million compared to the year ended December 31, 2017, primarily reflecting:
| • |
a $0.8 million decrease in gathering services and related fees as a result of volume declines. |
| • |
a $1.2 million decrease in operation and maintenance expense primarily due to declines in expenses for repairs to right-of-way of $0.9 million and lower property taxes of $0.7 million during the period. |
Corporate and Other Overview for the Years Ended December 31, 2019, 2018 and 2017
Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, transaction costs, interest expense and the early extinguishment of debt.
| Corporate and Other | ||||||||||||||||||||
| Year ended December 31, | Percentage Change | |||||||||||||||||||
| 2019 | 2018 | 2017 | 2019 v. 2018 | 2018 v. 2017 | ||||||||||||||||
| (Dollars in thousands) | ||||||||||||||||||||
|
Revenues: |
||||||||||||||||||||
|
Total revenues |
$ | 27,622 | $ | 78,161 | $ | 19,517 | * | * | ||||||||||||
|
Costs and expenses: |
||||||||||||||||||||
|
Cost of natural gas and NGLs |
26,107 | 78,172 | 19,264 | * | * | |||||||||||||||
|
General and administrative |
50,797 | 49,175 | 49,162 | 3 | % | 0 | % | |||||||||||||
|
Transaction costs |
3,017 | — | 50 | |||||||||||||||||
|
Interest expense |
91,966 | 82,830 | 88,701 | 11 | % | (7 | %) | |||||||||||||
|
Early extinguishment of debt (1) |
— | — | 22,039 | * | * | |||||||||||||||
| * |
Not considered meaningful |
| (1) |
Early extinguishment of debt includes $17.9 million paid for redemption and call premiums, as well as $4.1 million of unamortized debt issuance costs which were written off in connection with the repurchase of the outstanding $300.0 million 7.5% Senior Notes in the first quarter of 2017. |
Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $50.5 million compared to the year ended December 31, 2018 was attributable to lower natural gas, NGL and crude oil marketing activity.
The increase of $58.6 million compared to the year ended December 31, 2017 was attributable to higher natural gas, NGL and crude oil marketing activity.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $52.1 million compared to the year ended December 31, 2018 was attributable to lower marketing activity.
The increase of $58.9 million compared to the year ended December 31, 2017 was attributable to higher marketing activity.
General and Administrative. General and administrative expense increased $1.6 million compared to the year ended December 31, 2018, primarily due to a $7.5 million increase in severance and restructuring expenses partially offset by lower headcount associated with our cost cutting initiatives and lower performance-based compensation.
General and administrative expense were flat compared to the year ended December 31, 2017.
Transaction costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $2.1 million in financial advisory costs associated with restructuring the equity of certain subsidiaries in 2019.
EX 99.2-27
Interest Expense. Interest expense increased $9.1 million compared to the year ended December 31, 2018 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.
Interest expense decreased $5.9 million compared to the year ended December 31, 2017 as a result of (i) the tender and redemption of the $300.0 million principal 7.5% Senior Notes, (ii) the issuance of 300,000 Series A Preferred Units in November 2017 whereby the net proceeds were used to repay outstanding borrowings under our Revolving Credit Facility, (iii) a lower average outstanding balance on the Revolving Credit Facility and (iv) a lower outstanding balance on the Term Loan B. The decrease was partially offset by the interest associated with issuance of the $500.0 million principal 5.75% Senior Notes and an increase in the interest rate on the Revolving Credit Facility.
Early Extinguishment of Debt. The early extinguishment of debt recognized during the year ended December 31, 2017 was driven by the tender and redemption of the $300.0 million principal amount of 7.5% Senior Notes.
Summarized Financial Information
On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.
Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.
The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9 to the unaudited condensed consolidated financial statements). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 in this Exhibit 99.2 on Form 8-K as of and for the year ended December 31, 2019.
The supplemental summarized financial information below reflects SMLP’s separate accounts, the combined accounts of Summit Holdings and its 100% owned finance subsidiary, Finance Corp (the “Co-Issuers”) and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the “Obligor Group”) for the dates and periods indicated. The financial information of the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.
Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and Permian Holdco and Summit Permian Transmission, who are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes.
A list of each of SMLP’s subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to our Quarterly Report for the three months ended March 31, 2020 on Form 10-Q filed with the Securities and Exchange Commission on May 8, 2020.
EX 99.2-28
Summarized Balance Sheet Information. Summarized balance sheet information as of December 31, 2019 follow.
| December 31, 2019 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Assets |
||||||||
|
Current assets |
$ | 7,396 | $ | 104,964 | ||||
|
Noncurrent assets |
9,835 | 2,389,032 | ||||||
|
Liabilities |
||||||||
|
Current liabilities |
$ | 14,527 | $ | 69,177 | ||||
|
Noncurrent liabilities |
163,163 | 1,514,250 | ||||||
Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities’ results would have been had they operated on a stand-alone basis. Summarized statements of operations for the year ended December 31, 2019 follow.
| Year ended December 31, 2019 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Total revenues |
$ | — | $ | 443,528 | ||||
|
Total costs and expenses |
8,719 | 397,939 | ||||||
|
Loss before income taxes and loss from equity method investees |
(25,805 | ) | (28,840 | ) | ||||
|
Loss from equity method investees (1) |
— | (336,950 | ) | |||||
|
Net loss |
(27,036 | ) | (365,790 | ) | ||||
| (1) |
Amount includes a $329.7 million impairment of our equity method investment in Ohio Gathering and a $6.3 million impairment of long-lived assets in OCC. |
Liquidity and Capital Resources
Based on the terms of our Partnership Agreement, we expect that we will make distributions to our unitholders with cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, preferred equity and equity securities and proceeds from potential asset divestitures.
Capital Markets Activity
January 2020 Shelf Registration Statement. In November 2019, we filed the 2020 SRS which registered an indeterminate amount of common units, preferred units, warrants, rights, debt securities and guarantees. In January 2020, the SEC declared the 2020 SRS effective. There have been no transactions executed on the 2020 SRS.
July 2017 Shelf Registration Statement. In July 2017, we filed the 2017 SRS with the SEC to issue an indeterminate amount of debt, equity securities and guarantees. In November 2017, we filed a post-effective amendment to the 2017 SRS with the SEC to register, in addition to the classes of securities originally registered, an indeterminate amount of preferred units representing limited partner interests in the Partnership. The 2017 SRS expires in July 2020. However, we are no longer a well-known seasoned issuer and are therefore not able to use the 2017 SRS.
The following transaction was executed pursuant thereto:
| • |
In November 2017, we issued 300,000 9.50% Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units representing limited partner interests in the Partnership at a price to the public of $1,000 per unit. We used the net proceeds of $293.2 million (after deducting underwriting discounts and offering expenses) to repay outstanding borrowings under our Revolving Credit Facility. |
EX 99.2-29
November 2016 Shelf Registration Statement. In October 2016, we filed the 2016 SRS and in November 2016, the SEC declared it effective. The following transactions have been executed pursuant thereto:
| • |
In February 2017, we completed a secondary public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under our Partnership Agreement. We did not receive any proceeds from this secondary offering. |
| • |
In February 2017, we executed a new equity distribution agreement and filed a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the “ATM Program”). Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC rules. During the years ended December 31, 2019 and 2018, we did not issue any units under the ATM Program. During the year ended December 31, 2017, we issued 763,548 units under the ATM Program for aggregate gross proceeds of $17.7 million, and paid approximately $0.2 million as compensation to the sales agents pursuant to the terms of the equity distribution agreement. Our General Partner made capital contributions to maintain its approximate 2% General Partner interest in SMLP. |
The 2016 SRS expired in November 2019.
Debt
Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. On May 26, 2017, Summit Holdings closed on the Third Amended and Restated Credit Agreement which extended the maturity from November 2018 to May 2022 (see Note 10 to the consolidated financial statements). As of December 31, 2019, the outstanding balance of the Revolving Credit Facility was $677.0 million and the unused portion totaled $563.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. There were no defaults or events of default during 2019, and as of December 31, 2019, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 10 and 16 to the consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively.
Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the year ended December 31, 2019 on either series of senior notes.
SMP Holdings Term Loan. On March 21, 2017, SMP Holdings closed on a $300.0 million senior secured term loan facility, (the “Term Loan B”) with the maturity date of May 15, 2022. At December 31, 2019, the outstanding balance of the Term Loan B was $161.5 million and we were in compliance the Term Loan B’s financial covenants. There were no defaults or events of default during the year ended December 31, 2019.
For additional information on our long-term debt, see Notes 10 and 18 to the consolidated financial statements.
LIBOR Transition
LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations.
EX 99.2-30
We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined.
Cash Flows
The components of the net change in cash, cash equivalents and restricted cash were as follows:
| Year ended December 31, | ||||||||||||
| 2019 | 2018 | 2017 | ||||||||||
| (In thousands) | ||||||||||||
|
Net cash provided by operating activities |
$ | 161,741 | $ | 206,230 | $ | 213,048 | ||||||
|
Net cash used in investing activities |
(90,870 | ) | (205,298 | ) | (147,886 | ) | ||||||
|
Net cash (used in) provided by financing activities |
(50,122 | ) | 1,645 | (63,129 | ) | |||||||
|
|
|
|
|
|
|
|||||||
|
Net change in cash, cash equivalents and restricted cash |
$ | 20,749 | $ | 2,577 | $ | 2,033 | ||||||
|
|
|
|
|
|
|
|||||||
Operating activities. Cash flows from operating activities for the year ended December 31, 2019, primarily reflected:
| • |
a $7.3 million increase in cash interest payments; and |
| • |
other changes in working capital. |
Cash flows from operating activities for the year ended December 31, 2018, primarily reflected:
| • |
a $3.0 million decrease in cash interest payments primarily due to the extinguishment of the 7.5% Senior Notes in the first quarter of 2017; |
| • |
a decrease in distributions from equity method investees; and |
| • |
other changes in working capital. |
Investing activities. Details of cash flows from investing activities follow.
Cash flows used in investing activities during the year ended December 31, 2019 primarily reflected:
| • |
$182.3 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $80.5 million, Summit Permian of $45.0 million, the Williston Basin of $30.9 million and Corporate and Other, which includes $17.7 million of capital expenditures relating to the Double E Project; |
| • |
$18.3 million for investments in the Double E joint venture relating to the Double E Project; |
| • |
$89.5 million of net proceeds from the Tioga Midstream sale and $12.0 million of proceeds from the Red Rock Gathering sale; and |
| • |
$7.3 million for a distribution from an equity method investment. |
Cash flows used in investing activities during the year ended December 31, 2018 primarily reflected:
| • |
$200.6 million of capital expenditures primarily attributable to the ongoing development of the Permian Basin of $83.8 million as well as the continued development in the DJ Basin of $64.9 million, and the Williston Basin of $25.2 million; and |
| • |
$4.9 million of capital contributions to Ohio Gathering. |
Financing activities. Details of cash flows from financing activities follow.
Cash flows used in financing activities during the year ended December 31, 2019 primarily reflected:
| • |
$218.1 million of distributions; |
| • |
$211.0 million of net borrowings under our Revolving Credit Facility; |
| • |
$65.3 million of payments on the Term Loan B; and |
EX 99.2-31
| • |
$27.4 of net proceeds from the issuance of Subsidiary Series A Preferred Units. |
Cash flows used in financing activities during the year ended December 31, 2018 primarily reflected:
| • |
$149.4 million of distributions; |
| • |
$205.0 million of net borrowings under our Revolving Credit Facility; and |
| • |
$49.3 million of payments on the Term Loan B. |
Contractual Obligations Update
The table below summarizes our contractual obligations as of December 31, 2019.
| Total |
Less than
1 year |
1-3 years | 3-5 years |
More than
5 years |
||||||||||||||||
| (In thousands) | ||||||||||||||||||||
|
Long-term debt and interest payments (1) |
$ | 1,936,866 | $ | 91,481 | $ | 1,273,510 | $ | 57,500 | $ | 514,375 | ||||||||||
|
Purchase obligations (2) |
132,622 | 132,622 | — | — | — | |||||||||||||||
|
Finance leases (3) |
1,991 | 1,299 | 692 | — | — | |||||||||||||||
|
Operating leases (3) |
4,803 | 1,705 | 1,555 | 648 | 895 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Total contractual obligations |
$ | 2,076,282 | $ | 227,107 | $ | 1,275,757 | $ | 58,148 | $ | 515,270 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (1) |
For the purpose of calculating future interest on the Revolving Credit Facility and the Term Loan B, assumes no change in balance or rate from December 31, 2019. Includes a 0.50% commitment fee on the unused portion of the Revolving Credit Facility and a 0.125% fronting fee on the outstanding but undrawn irrevocable standby letter of credit. See Note 10 to the consolidated financial statements. |
| (2) |
Represents agreements to purchase goods or services that are enforceable and legally binding. |
| (3) |
See Item 2. Properties and Note 16 to the consolidated financial statements. |
Capital Requirements
Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either:
| • |
maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
| • |
expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
For the year ended December 31, 2019, cash paid for capital expenditures totaled $182.3 million (see Note 4 to the consolidated financial statements) which included $14.2 million of maintenance capital expenditures. For the year ended December 31, 2019, there were no contributions to Ohio Gathering and we contributed $18.3 million to Double E (see Note 8 to the consolidated financial statements).
For the year ended December 31, 2018, cash paid for capital expenditures totaled $200.6 million, compared with $124.2 million for the year ended December 31, 2017 (see Note 4 to the consolidated financial statements). Maintenance capital expenditures totaled $21.4 million for the year ended December 31, 2018 compared to $15.6 million for the year ended December 31, 2017. For the year ended December 31, 2018, contributions to equity method investees totaled $4.9 million, compared with $25.5 million for the year ended December 31, 2017 (see Note 8 to the consolidated financial statements). The year-over-year increase in cash paid for capital expenditures primarily reflected the expansion of our existing gathering and processing complex in the DJ Basin with the addition of a new 60 MMcf/d cryogenic processing plant in addition to the development of our new associated natural gas gathering and processing system in the Permian Basin.
EX 99.2-32
We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity.
With the completion of our 60 MMcf/d DJ Basin processing plant and compression expansions in the Permian Basin, capital expenditures began to decline in the third and fourth quarter of 2019. We will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit neutral to Summit. We are currently targeting a financing structure that limits cash payments by us during 2020, and which shifts a substantial majority of our Double E capital commitments to third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units to TPG for net proceeds of $27.3 million.
We estimate that our 2020 capital program will range from $50 million to $70 million, including approximately $10 million related to our equity method investment in Double E.
There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreement with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.
Credit and Counterparty Concentration Risks
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.
Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.
We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting its MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.
For additional information, see Notes 4, 9 and 11 to the consolidated financial statements.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the year ended December 31, 2019.
Critical Accounting Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the consolidated financial statements.
The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value. The preparation and evaluation of these critical accounting estimates involve
EX 99.2-33
the use of various assumptions developed from management’s analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows:
Recognition and Impairment of Long-Lived Assets
Our long-lived assets include property, plant and equipment and amortizing intangible assets.
Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2019, we had net property, plant and equipment with a carrying value of approximately $1.9 billion and net amortizing intangible assets with a carrying value of approximately $232.3 million.
When evidence exists that we will not be able to recover a long-lived asset’s carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable as well as in connection with any goodwill impairment evaluations.
With respect to property, plant and equipment and our amortizing intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset’s use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset’s fair value. We determine fair value using an income-based and market-based approach in which we discount the asset’s expected future cash flows to reflect the risk associated with achieving the underlying cash flows. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.
2019 Impairments. In the DJ Basin, we determined that certain processing plant assets related to our existing 20 MMcf/d plant would no longer be utilized due to our expansion plans for the Niobrara G&P system. Based on the results of the recoverability assessment and the conclusion that the carrying value was not fully recoverable, we recorded an impairment charge of $34.7 million related to these assets in the first quarter of 2019.
In the Piceance Basin, we sold certain Red Rock Gathering system assets for a cash purchase price of $12.0 million. Prior to closing, we recorded an impairment charge of $14.2 million in the fourth quarter of 2019 based on the expected consideration and the carrying value for the Red Rock Gathering system assets.
In the Barnett Shale, we determined that certain compressor station assets would be shut down and decommissioned. As a result, we recorded an impairment charge of $9.7 million related to these assets in the first quarter of 2019. Also in connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of rights-of-way intangible assets. We concluded the rights-of-way intangible assets were also impaired and, as a result, we recorded an impairment charge of $0.5 million in the first quarter of 2019.
In the Permian Basin, in connection with the cancellation of a project, we determined certain processing plant assets and the related rights-of-way intangible assets would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million and $0.6 million related to the processing plant assets and rights-of-way intangible assets, respectively, in the fourth quarter of 2019. See Notes 5 and 6 for additional details.
2018 Impairments. In December 2018, in connection with certain strategic initiatives, we performed a recoverability assessment of certain assets within the Williston Basin reporting segment. Based on the results, we concluded that the carrying value of certain long-lived assets related to the Tioga Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $3.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. In addition, we reviewed other assets that had been identified as potentially impaired and recognized long-lived asset impairments as detailed in Note 5 to the consolidated financial statements.
EX 99.2-34
2017 Impairments. In December 2017, in connection with certain strategic initiatives, we performed a financial review of certain assets within the Williston Basin reporting segment. This resulted in a triggering event that required us to perform a recoverability test. Based on the results of the test, we concluded that the carrying value of certain long-lived assets and the related intangible assets related to the Bison Midstream system in the Williston Basin were not fully recoverable. As a result, we recorded an impairment charge of $101.9 million related to the long-lived assets and $85.2 million related to contract intangibles assets.
For additional information, see Notes 2, 5 and 6 to the consolidated financial statements.
Goodwill. We evaluate goodwill for impairment annually on September 30 and whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill.
2019 Impairment Evaluation. We performed our annual goodwill impairment testing for the Mountaineer Midstream reporting unit as of September 30, 2019 using a combination of the income and market approaches. We determined that the fair value of the Mountaineer Midstream reporting unit did not exceed its carrying value, including goodwill. As a result, we recognized a goodwill impairment charge of $16.2 million for the year ended December 31, 2019.
2018 and 2017 Impairment Evaluations. We performed our 2018 and 2017 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.
See Notes 2 and 7 for additional information.
Minimum Volume Commitments
Adjustments for MVC Shortfall Payments. We estimate the impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA. Adjustments related to MVC shortfall payments account for:
| • |
the net increases or decreases in deferred revenue for MVC shortfall payments and |
| • |
our inclusion of expected annual MVC shortfall payments. We also included a proportional amount of any historical and expected MVC shortfall payments in each quarter prior to the quarter in which we actually recognized the shortfall payment. |
We estimate expected MVC shortfall payments based on assumptions including, but not limited to, contract terms, historical volume throughput data and expectations regarding future investment, drilling and production.
For additional information, see Notes 2, 4 and 9 to the consolidated financial statements and the “Results of Operations” and “Liquidity and Capital Resources—Credit and Counterparty Concentration Risks” sections herein.
Forward-Looking Statements
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, our subsidiaries, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to
EX 99.2-35
persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:
| • |
our ability to sustain our current rate of cash distributions; |
| • |
fluctuations in natural gas, NGLs and crude oil prices; |
| • |
the extent and success of our customers’ drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets; |
| • |
failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; |
| • |
competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; |
| • |
actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; |
| • |
our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; |
| • |
the ability to attract and retain key management personnel; |
| • |
commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets; |
| • |
changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets; |
| • |
restrictions placed on us by the agreements governing our debt and preferred equity instruments; |
| • |
the availability, terms and cost of downstream transportation and processing services; |
| • |
natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control; |
| • |
operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water; |
| • |
weather conditions and terrain in certain areas in which we operate; |
| • |
any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities; |
| • |
timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; |
| • |
our ability to finance our obligations related to capital expenditures including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; |
| • |
the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; |
| • |
the ability of SMP Holdings to meet its obligations under its senior secured term loan facility; |
| • |
changes in tax status; |
| • |
the effects of litigation; |
| • |
changes in general economic conditions; and |
| • |
certain factors discussed elsewhere in this report. |
EX 99.2-36
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, preferred units and senior notes.
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.
EX 99.2-37
|
Report of Independent Registered Public Accounting Firm
|
EX 99.3-3
|
|||
|
Consolidated Balance Sheets as of December 31, 2019 and 2018
|
EX
99.3-4
|
|||
|
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017
|
EX
99.3-5
|
|||
|
Consolidated Statements of Partners’ Capital for the years ended December 31, 2019, 2018 and 2017
|
EX 99.3-6 | |||
|
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017
|
EX 99.3-7 | |||
|
Notes to Consolidated Financial Statements
|
EX 99.3-9 | |||
|
1. Organization, Business Operations and Presentation and Consolidation
|
EX 99.3-9 | |||
|
2. Summary of Significant Accounting Policies
|
EX 99.3-10
|
|||
|
3. Revenue
|
EX 99.3-15 | |||
|
4. Segment Information
|
EX 99.3-17 | |||
|
5. Property, Plant and Equipment, Net
|
EX 99.3-21 | |||
|
6. Amortizing Intangible Assets
|
EX 99.3-23 | |||
|
7. Goodwill
|
EX 99.3-24 | |||
|
8. Equity Method Investments
|
EX 99.3-24 | |||
|
9. Deferred Revenue
|
EX 99.3-26 | |||
|
10. Debt
|
EX 99.3-28 | |||
|
11. Financial Instruments
|
EX 99.3-32 | |||
|
12. Partners’ Capital and Mezzanine Capital
|
EX 99.3-32 | |||
|
13. Earnings Per Unit
|
EX 99.3-35 | |||
|
14. Unit-Based and Noncash Compensation
|
EX 99.3-35 | |||
|
15. Related-Party Transactions
|
EX 99.3-36 | |||
|
16. Leases, Commitments and Contingencies
|
EX 99.3-37 | |||
|
17. Dispositions, Drop Down Transactions and Restructuring
|
EX 99.3-41 | |||
|
18. Unaudited Quarterly Financial Data
|
EX 99.3-42 | |||
|
19. Subsequent Events
|
EX 99.3-43 |
|
December 31,
2019 |
December 31,
2018 |
|||||||
|
(In thousands, except unit amounts)
|
||||||||
|
Assets
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 9,530 | $ | 16,173 | ||||
|
Restricted cash
|
27,392 | — | ||||||
|
Accounts receivable
|
97,418 | 97,936 | ||||||
|
Other current assets
|
5,521 | 4,388 | ||||||
|
|
|
|
|
|||||
|
Total current assets
|
139,861 | 118,497 | ||||||
|
Property, plant and equipment, net
|
1,882,489 | 1,964,099 | ||||||
|
Intangible assets, net
|
232,278 | 273,416 | ||||||
|
Goodwill
|
— | 16,211 | ||||||
|
Investment in equity method investees
|
309,728 | 649,250 | ||||||
|
Other noncurrent assets
|
9,742 | 11,746 | ||||||
|
|
|
|
|
|||||
|
Total assets
|
$ | 2,574,098 | $ | 3,033,219 | ||||
|
|
|
|
|
|||||
|
Liabilities and Capital
|
||||||||
|
Current liabilities:
|
||||||||
|
Trade accounts payable
|
$ | 24,415 | $ | 38,415 | ||||
|
Accrued expenses
|
11,339 | 26,763 | ||||||
|
Deferred revenue
|
13,493 | 11,467 | ||||||
|
Ad valorem taxes payable
|
8,477 | 10,550 | ||||||
|
Accrued interest
|
12,346 | 12,339 | ||||||
|
Accrued environmental remediation
|
1,725 | 2,487 | ||||||
|
Other current liabilities
|
12,206 | 13,236 | ||||||
|
Current portion of long-term debt
|
5,546 | 14,500 | ||||||
|
|
|
|
|
|||||
|
Total current liabilities
|
89,547 | 129,757 | ||||||
|
Long-term debt
|
1,622,279 | 1,464,280 | ||||||
|
Noncurrent deferred revenue
|
38,709 | 39,504 | ||||||
|
Noncurrent accrued environmental remediation
|
2,926 | 3,149 | ||||||
|
Other noncurrent liabilities
|
7,951 | 4,962 | ||||||
|
|
|
|
|
|||||
|
Total liabilities
|
1,761,412 | 1,641,652 | ||||||
|
Commitments and contingencies (Note 16)
|
||||||||
|
Mezzanine Capital
|
||||||||
|
Subsidiary Series A Preferred Units (30,058 units issued and outstanding at December 31, 2019)
|
27,450 | — | ||||||
|
Partners’ Capital
|
||||||||
|
Series A Preferred Units (300,000 units issued and outstanding at December 31, 2019 and December 31, 2018)
|
293,616 | 293,616 | ||||||
|
Common limited partner capital
|
305,550 | 543,479 | ||||||
|
Noncontrolling interest
|
186,070 | 554,472 | ||||||
|
|
|
|
|
|||||
|
Total partners’ capital
|
785,236 | 1,391,567 | ||||||
|
|
|
|
|
|||||
|
Total liabilities, mezzanine capital and partners’ capital
|
$ | 2,574,098 | $ | 3,033,219 | ||||
|
|
|
|
|
|||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands, except
per-unit
amounts)
|
||||||||||||
|
Revenues:
|
||||||||||||
|
Gathering services and related fees
|
$ | 326,747 | $ | 344,616 | $ | 394,427 | ||||||
|
Natural gas, NGLs and condensate sales
|
86,994 | 134,834 | 68,459 | |||||||||
|
Other revenues
|
29,787 | 27,203 | 25,855 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total revenues
|
443,528 | 506,653 | 488,741 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Costs and expenses:
|
||||||||||||
|
Cost of natural gas and NGLs
|
63,438 | 107,661 | 57,237 | |||||||||
|
Operation and maintenance
|
98,719 | 100,978 | 93,882 | |||||||||
|
General and administrative
|
55,947 | 54,991 | 56,351 | |||||||||
|
Depreciation and amortization
|
110,354 | 107,263 | 115,737 | |||||||||
|
Transaction costs
|
3,017 | — | 50 | |||||||||
|
(Gain) loss on asset sales, net
|
(1,536 | ) | — | 527 | ||||||||
|
Long-lived asset impairment
|
60,507 | 7,186 | 188,702 | |||||||||
|
Goodwill impairment
|
16,211 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total costs and expenses
|
406,657 | 378,079 | 512,486 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Other income (expense)
|
451 | (169 | ) | 298 | ||||||||
|
Interest expense
|
(91,966 | ) | (82,830 | ) | (88,701 | ) | ||||||
|
Early extinguishment of debt
|
— | — | (22,039 | ) | ||||||||
|
|
|
|
|
|
|
|||||||
|
(Loss) income before income taxes and loss from equity method investees
|
(54,644 | ) | 45,575 | (134,187 | ) | |||||||
|
Income tax expense
|
(1,231 | ) | (367 | ) | (504 | ) | ||||||
|
Loss from equity method investees
|
(337,851 | ) | (10,888 | ) | (2,223 | ) | ||||||
|
|
|
|
|
|
|
|||||||
|
Net (loss) income
|
$ | (393,726 | ) | $ | 34,320 | $ | (136,914 | ) | ||||
|
|
|
|
|
|
|
|||||||
|
Less:
|
||||||||||||
|
Net (loss) income attributable to noncontrolling interest
|
(209,275 | ) | 2,774 | 46,497 | ||||||||
|
|
|
|
|
|
|
|||||||
|
Net (loss) income attributable to limited partners
|
(184,451 | ) | 31,546 | (183,411 | ) | |||||||
|
Net income attributable to Series A Preferred Units
|
28,500 | 28,500 | 3,563 | |||||||||
|
Net income attributable to Subsidiary Series A Preferred Units
|
58 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Net (loss) income attributable to common limited partners
|
$ | (213,009 | ) | $ | 3,046 | $ | (186,974 | ) | ||||
|
|
|
|
|
|
|
|||||||
|
(Loss) income per limited partner unit:
|
||||||||||||
|
Common unit – basic
|
$ | (4.70 | ) | $ | 0.07 | $ | (4.13 | ) | ||||
|
Common unit – diluted
|
$ | (4.70 | ) | $ | 0.07 | $ | (4.13 | ) | ||||
|
Weighted-average limited partner units outstanding:
|
||||||||||||
|
Common units – basic
|
45,319 | 45,319 | 45,319 | |||||||||
|
Common units – diluted
|
45,319 | 45,630 | 45,319 | |||||||||
|
Noncontrolling Interest
|
||||||||||||||||
|
Series A Preferred
Units |
Common
Noncontrolling Interests (1) |
Partners’ Capital
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Partners’ capital, January 1, 2017
|
$ | — | $ | 629,488 | $ | 1,005,932 | $ | 1,635,420 | ||||||||
|
Net income (loss)
|
3,563 | 46,497 | (186,974 | ) | (136,914 | ) | ||||||||||
|
Unit-based compensation
|
— | 7,878 | — | 7,878 | ||||||||||||
|
Effect of common unit issuances under SMLP LTIP
|
— | 1,209 | (1,209 | ) | — | |||||||||||
|
Tax withholdings on vested SMLP LTIP awards
|
— | (2,236 | ) | — | (2,236 | ) | ||||||||||
|
Net cash distributions to SMLP unitholders
|
(2,375 | ) | (107,598 | ) | — | (109,973 | ) | |||||||||
|
Net cash distributions to Energy Capital Partners
|
— | — | (301,672 | ) | (301,672 | ) | ||||||||||
|
Issuance of Series A Preferred Units, net of offering costs
|
293,238 | — | — | 293,238 | ||||||||||||
|
ATM Program issuances, net of costs
|
— | 14,551 | 2,527 | 17,078 | ||||||||||||
|
Secondary offering of SMLP common units
|
— | 60,981 | 33,659 | 94,640 | ||||||||||||
|
Other
|
— | (199 | ) | — | (199 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, December 31, 2017, as reported
|
$ | 294,426 | $ | 650,571 | $ | 552,263 | $ | 1,497,260 | ||||||||
|
January 1, 2018 impact of Topic 606 day 1 adoption
|
— | 2,669 | 1,545 | 4,214 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, January 1, 2018
|
294,426 | 653,240 | 553,808 | 1,501,474 | ||||||||||||
|
Net income
|
28,500 | 2,774 | 3,046 | 34,320 | ||||||||||||
|
Net cash distributions to SMLP unitholders
|
(28,500 | ) | (109,101 | ) | — | (137,601 | ) | |||||||||
|
Net cash distributions to Energy Capital Partners
|
— | — | (11,800 | ) | (11,800 | ) | ||||||||||
|
Unit-based compensation
|
— | 8,088 | — | 8,088 | ||||||||||||
|
Effect of common unit issuances under SMLP LTIP
|
— | 1,575 | (1,575 | ) | — | |||||||||||
|
Tax withholdings on vested SMLP LTIP awards
|
— | (1,974 | ) | — | (1,974 | ) | ||||||||||
|
Other
|
(810 | ) | (130 | ) | — | (940 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, December 31, 2018
|
$ | 293,616 | $ | 554,472 | $ | 543,479 | $ | 1,391,567 | ||||||||
|
Net income (loss)
|
28,500 | (209,275 | ) | (213,009 | ) | (393,784 | ) | |||||||||
|
Net cash distributions to noncontrolling interest SMLP unitholders
|
(28,500 | ) | (68,874 | ) | — | (97,374 | ) | |||||||||
|
Net cash distributions to Energy Capital Partners
|
— | — | (120,730 | ) | (120,730 | ) | ||||||||||
|
Unit-based compensation
|
— | 8,171 | — | 8,171 | ||||||||||||
|
Effect of common unit issuances under SMLP LTIP
|
— | 2,664 | (2,664 | ) | — | |||||||||||
|
Tax withholdings on vested SMLP LTIP awards
|
— | (2,614 | ) | — | (2,614 | ) | ||||||||||
|
Conversion of noncontrolling interest related to cancelation of subsidiary incentive distribution rights
|
— | (48,203 | ) | 48,203 | — | |||||||||||
|
Conversion of noncontrolling interest related to partial cancellation of subsidiary of DPPO
|
— | (50,271 | ) | 50,271 | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, December 31, 2019
|
$ | 293,616 | $ | 186,070 | $ | 305,550 | $ | 785,236 | ||||||||
| (1) |
Prior to the GP
Buy-In
Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Cash flows from operating activities:
|
||||||||||||
|
Net (loss) income
|
$ | (393,726 | ) | $ | 34,320 | $ | (136,914 | ) | ||||
|
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
|
||||||||||||
|
Depreciation and amortization
|
111,574 | 106,930 | 115,134 | |||||||||
|
Noncash lease expense
|
3,086 | — | — | |||||||||
|
Amortization of debt issuance costs
|
6,313 | 6,142 | 5,445 | |||||||||
|
Unit-based and noncash compensation
|
8,171 | 8,328 | 7,951 | |||||||||
|
Loss from equity method investees
|
337,851 | 10,888 | 2,223 | |||||||||
|
Distributions from equity method investees
|
37,300 | 35,271 | 40,220 | |||||||||
|
(Gain) loss on asset sales, net
|
(1,536 | ) | — | 527 | ||||||||
|
Long-lived asset impairment
|
60,507 | 7,186 | 188,702 | |||||||||
|
Goodwill impairment
|
16,211 | — | — | |||||||||
|
Early extinguishment of debt
|
— | — | 22,039 | |||||||||
|
Write-off
of debt issuance costs
|
— | — | 302 | |||||||||
|
Changes in operating assets and liabilities:
|
||||||||||||
|
Accounts receivable
|
(5,466 | ) | (25,635 | ) | 25,063 | |||||||
|
Trade accounts payable
|
(96 | ) | 85 | (3,256 | ) | |||||||
|
Accrued expenses
|
(10,572 | ) | 13,903 | 1,227 | ||||||||
|
Deferred revenue, net
|
1,683 | 5,355 | (40,758 | ) | ||||||||
|
Ad valorem taxes payable
|
(1,525 | ) | 2,211 | (2,248 | ) | |||||||
|
Accrued interest
|
7 | (140 | ) | (7,736 | ) | |||||||
|
Accrued environmental remediation, net
|
(1,152 | ) | 292 | (4,109 | ) | |||||||
|
Other, net
|
(6,889 | ) | 1,094 | (764 | ) | |||||||
|
|
|
|
|
|
|
|||||||
|
Net cash provided by operating activities
|
161,741 | 206,230 | 213,048 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Cash flows from investing activities:
|
||||||||||||
|
Capital expenditures
|
(182,291 | ) | (200,586 | ) | (124,215 | ) | ||||||
|
Proceeds from asset sale (net of cash of $1,475 for the year ended December 31, 2019)
|
102,111 | 496 | 2,300 | |||||||||
|
Contributions to equity method investees
|
— | (4,924 | ) | (25,513 | ) | |||||||
|
Distributions from equity method investment
|
7,313 | — | — | |||||||||
|
Investment in equity method investee
|
(18,316 | ) | — | — | ||||||||
|
Other, net
|
313 | (284 | ) | (458 | ) | |||||||
|
|
|
|
|
|
|
|||||||
|
Net cash used in investing activities
|
(90,870 | ) | (205,298 | ) | (147,886 | ) | ||||||
|
|
|
|
|
|
|
|||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Cash flows from financing activities:
|
||||||||||||
|
Distributions to noncontrolling interest SMLP unitholders
|
(68,874 | ) | (109,101 | ) | (107,598 | ) | ||||||
|
Distributions to Series A Preferred unitholders
|
(28,500 | ) | (28,500 | ) | (2,375 | ) | ||||||
|
Distributions to mandatorily redeemable Class C unitholders
|
— | — | (99,323 | ) | ||||||||
|
Distributions to
Energy Capital Partners
|
(120,730 | ) | (11,800 | ) | (301,672 | ) | ||||||
|
Borrowings under Revolving Credit Facility
|
369,000 | 289,000 | 247,500 | |||||||||
|
Repayments under Revolving Credit Facility
|
(158,000 | ) | (84,000 | ) | (634,500 | ) | ||||||
|
Borrowings under SMP Holdings Term Loan B
|
— | — | 300,000 | |||||||||
|
Repayments under SMP Holdings Term Loan B
|
(65,250 | ) | (49,250 | ) | (24,000 | ) | ||||||
|
Debt issuance costs
|
(673 | ) | (518 | ) | (25,061 | ) | ||||||
|
Payment of redemption and call premiums on senior notes
|
— | — | (17,932 | ) | ||||||||
|
Proceeds from ATM Program common unit issuances, net of costs
|
— | — | 17,078 | |||||||||
|
Proceeds from secondary offering common units, net of costs
|
— | — | 94,640 | |||||||||
|
Proceeds from issuance of Series A preferred units, net of costs
|
27,392 | — | 293,238 | |||||||||
|
Issuance of senior notes
|
— | — | 500,000 | |||||||||
|
Tender and redemption of senior notes
|
— | — | (300,000 | ) | ||||||||
|
Other, net
|
(4,487 | ) | (4,186 | ) | (3,124 | ) | ||||||
|
|
|
|
|
|
|
|||||||
|
Net cash (used in) provided by financing activities
|
(50,122 | ) | 1,645 | (63,129 | ) | |||||||
|
|
|
|
|
|
|
|||||||
|
Net change in cash, cash equivalents and restricted cash
|
20,749 | 2,577 | 2,033 | |||||||||
|
Cash, cash equivalents and restricted cash, beginning of period
|
16,173 | 13,596 | 11,563 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Cash, cash equivalents and restricted cash, end of period (1)
|
$ | 36,922 | $ | 16,173 | $ | 13,596 | ||||||
|
|
|
|
|
|
|
|||||||
|
Supplemental cash flow disclosures:
|
||||||||||||
|
Cash interest paid
|
$ | 92,536 | $ | 85,233 | $ | 88,193 | ||||||
|
Less capitalized interest
|
6,974 | 8,497 | 2,579 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Interest paid (net of capitalized interest)
|
$ | 85,562 | $ | 76,736 | $ | 85,614 | ||||||
|
|
|
|
|
|
|
|||||||
|
Cash paid for taxes
|
$ | 150 | $ | 175 | $ | — | ||||||
|
Noncash investing and financing activities
|
||||||||||||
|
Capital expenditures in trade accounts payable (period-end accruals)
|
$ | 19,846 | $ | 33,750 | $ | 11,792 | ||||||
|
Asset contribution to an equity method investment
|
23,643 | — | — | |||||||||
|
Capital expenditures relating to contributions in aid of construction for Topic 606 day 1 adoption
|
— | 33,123 | — | |||||||||
|
Right-of-use
|
5,448 | — | — | |||||||||
| (1) |
A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow:
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Cash and cash equivalents
|
$ | 9,530 | $ | 16,173 | $ | 13,596 | ||||||
|
Restricted cash
|
27,392 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total cash, cash equivalents and restricted cash
|
$ | 36,922 | $ | 16,173 | $ | 13,596 | ||||||
|
|
|
|
|
|
|
|||||||
| • |
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
|
| • |
Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
|
| • |
Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
|
| • |
Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
|
| • |
Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming;
|
| • |
Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico;
|
| • |
Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas;
|
| • |
Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;
|
| • |
DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
|
| • |
Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.
|
|
Useful lives
(In years)
|
||||
|
Gathering and processing systems and related equipment
|
12-30
|
|||
|
Other
|
4-15
|
|||
| • |
Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities;
|
| • |
Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and
|
| • |
Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management’s fair value measurement).
|
| • |
Fee-based
arrangements.
fee-based
arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, compressing and/or processing and (ii) crude oil and/or produced water gathering.
|
| • |
Percent-of-proceeds
percent-of-proceeds
|
| • |
ASU
No. 2016-02
Leases (“Topic 842”). We adopted Topic 842 with a date of initial application of January 1, 2019. We applied Topic 842 by recognizing (i) a $5.4 million
right-of-use
|
| • |
ASU
No. 2018-13
Fair Value Measurement (“ASU
2018-13”).
ASU
2018-13
updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU
2018-13
modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU
2018-13
removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU
2018-13
on January 1, 2020 did not have a material impact on our consolidated financial statement disclosures.
|
| • |
ASU
No. 2016-13
Financial Instruments – Credit Losses (“ASU
2016-13”).
ASU
2016-13
requires the use of a current expected loss model for financial assets measured at amortized cost and certain
off-balance
sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU
2016-13
on January 1, 2020 did not have a material impact on our consolidated financial statements or disclosures.
|
|
2020
|
2021
|
2022
|
2023
|
2024
|
Thereafter
|
|||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 122,055 | $ | 102,127 | $ | 84,736 | $ | 66,693 | $ | 50,608 | $ | 59,602 | ||||||||||||
|
Reportable Segments
|
||||||||||||||||||||||||||||||||||||||||
|
Year ended December 31, 2019
|
||||||||||||||||||||||||||||||||||||||||
|
Utica
Shale |
Williston
Basin |
DJ
Basin
|
Permian
Basin |
Piceance
Basin |
Barnett
Shale |
Marcellus
Shale |
Total
reportable segments |
All other
segments |
Total
|
|||||||||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||||||||||
|
Major products / services lines
|
||||||||||||||||||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 31,926 | $ | 77,626 | $ | 21,940 | $ | 3,610 | $ | 121,357 | $ | 47,862 | $ | 24,471 | $ | 328,792 | $ | (2,045 | ) | $ | 326,747 | |||||||||||||||||||
|
Natural gas, NGLs and condensate sales
|
— | 16,461 | 389 | 16,383 | 7,954 | 17,147 | — | 58,334 | 28,660 | 86,994 | ||||||||||||||||||||||||||||||
|
Other revenues
|
2,065 | 11,564 | 3,721 | 310 | 4,327 | 6,793 | — | 28,780 | 1,007 | 29,787 | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
Total
|
$ | 33,991 | $ | 105,651 | $ | 26,050 | $ | 20,303 | $ | 133,638 | $ | 71,802 | $ | 24,471 | $ | 415,906 | $ | 27,622 | $ | 443,528 | ||||||||||||||||||||
|
Reportable Segments
|
||||||||||||||||||||||||||||||||||||||||
|
Year ended December 31, 2018
|
||||||||||||||||||||||||||||||||||||||||
|
Utica
Shale |
Williston
Basin |
DJ
Basin
|
Permian
Basin |
Piceance
Basin |
Barnett
Shale |
Marcellus
Shale |
Total
reportable segments |
All other
segments |
Total
|
|||||||||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||||||||||
|
Major products / services lines
|
||||||||||||||||||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 35,233 | $ | 79,606 | $ | 11,251 | $ | 115 | $ | 135,810 | $ | 59,030 | $ | 29,573 | $ | 350,618 | $ | (6,002 | ) | $ | 344,616 | |||||||||||||||||||
|
Natural gas, NGLs and condensate sales
|
— | 31,840 | 371 | 843 | 14,800 | 2,523 | — | 50,377 | 84,457 | 134,834 | ||||||||||||||||||||||||||||||
|
Other revenues
|
— | 12,204 | 3,672 | — | 4,909 | 6,712 | — | 27,497 | (294 | ) | 27,203 | |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
Total
|
$ | 35,233 | $ | 123,650 | $ | 15,294 | $ | 958 | $ | 155,519 | $ | 68,265 | $ | 29,573 | $ | 428,492 | $ | 78,161 | $ | 506,653 | ||||||||||||||||||||
|
December 31, 2019
|
December 31, 2018
|
|||||||
|
(In thousands)
|
||||||||
|
Contract assets, beginning of period
|
$ | 8,755 | $ | — | ||||
|
Additions
|
18,077 | 26,403 | ||||||
|
Transfers out
|
(22,930 | ) | (17,648 | ) | ||||
|
|
|
|
|
|||||
|
Contract assets, end of period
|
$ | 3,902 | $ | 8,755 | ||||
| • |
the Utica Shale, which is served by Summit Utica;
|
| • |
Ohio Gathering, which includes our ownership interest in OGC and OCC;
|
| • |
the Williston Basin, which is served by Polar and Divide and Bison Midstream;
|
| • |
the DJ Basin, which is served by Niobrara G&P;
|
| • |
the Permian Basin, which is served by Summit Permian;
|
| • |
the Piceance Basin, which is served by Grand River;
|
| • |
the Barnett Shale, which is served by DFW Midstream; and
|
| • |
the Marcellus Shale, which is served by Mountaineer Midstream.
|
|
December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Assets (1):
|
||||||||||||
|
Utica Shale
|
$ | 206,368 | $ | 207,357 | $ | 212,311 | ||||||
|
Ohio Gathering
|
275,000 | 649,250 | 690,485 | |||||||||
|
Williston Basin
|
452,152 | 526,819 | 512,860 | |||||||||
|
DJ Basin
|
205,308 | 166,580 | 79,438 | |||||||||
|
Permian Basin
|
185,708 | 145,702 | 57,590 | |||||||||
|
Piceance Basin
|
631,140 | 699,638 | 719,284 | |||||||||
|
Barnett Shale
|
350,638 | 376,564 | 383,306 | |||||||||
|
Marcellus Shale
|
184,631 | 208,790 | 217,362 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total reportable segment assets
|
2,490,945 | 2,980,700 | 2,872,636 | |||||||||
|
Corporate and Other
|
83,153 | 56,838 | 35,332 | |||||||||
|
Eliminations
|
— | (4,319 | ) | (249 | ) | |||||||
|
|
|
|
|
|
|
|||||||
|
Total assets
|
$ | 2,574,098 | $ | 3,033,219 | $ | 2,907,719 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) |
At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E (included in the Investment in equity method investees caption of the consolidated balance sheet). At December 31, 2018, Corporate and Other included $9.6 million of capital expenditures relating to the Double E Project.
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Revenues (1):
|
||||||||||||
|
Utica Shale
|
$ | 33,991 | $ | 35,233 | $ | 38,907 | ||||||
|
Williston Basin
|
105,651 | 123,650 | 161,503 | |||||||||
|
DJ Basin
|
26,050 | 15,294 | 11,860 | |||||||||
|
Permian Basin
|
20,303 | 958 | — | |||||||||
|
Piceance Basin
|
133,638 | 155,519 | 154,893 | |||||||||
|
Barnett Shale
|
71,802 | 68,265 | 71,667 | |||||||||
|
Marcellus Shale
|
24,471 | 29,573 | 30,394 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total reportable segments revenue
|
415,906 | 428,492 | 469,224 | |||||||||
|
Corporate and Other
|
30,552 | 88,286 | 26,446 | |||||||||
|
Eliminations
|
(2,930 | ) | (10,125 | ) | (6,929 | ) | ||||||
|
|
|
|
|
|
|
|||||||
|
Total revenues
|
$ | 443,528 | $ | 506,653 | $ | 488,741 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) |
Excludes revenues earned by Ohio Gathering due to equity method accounting.
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
Percentage of total revenues (1):
|
||||||||||||
|
Counterparty A - Piceance Basin
|
11 | % | * | * | ||||||||
|
Counterparty B - Williston Basin
|
10 | % | * | 13 | % | |||||||
|
Counterparty C - Piceance Shale
|
* | 10 | % | * | ||||||||
| (1) |
Excludes revenues earned by Ohio Gathering due to equity method accounting.
|
| * |
Less than 10%
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Depreciation and amortization (1):
|
||||||||||||
|
Utica Shale
|
$ | 7,659 | $ | 7,672 | $ | 7,009 | ||||||
|
Williston Basin
|
19,829 | 22,642 | 33,772 | |||||||||
|
DJ Basin
|
3,732 | 3,133 | 2,636 | |||||||||
|
Permian Basin
|
4,868 | 243 | — | |||||||||
|
Piceance Basin
|
47,018 | 46,919 | 46,289 | |||||||||
|
Barnett Shale (2)
|
16,575 | 15,325 | 15,001 | |||||||||
|
Marcellus Shale
|
9,141 | 9,090 | 9,047 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total reportable segment depreciation and amortization
|
108,822 | 105,024 | 113,754 | |||||||||
|
Corporate and Other
|
2,752 | 1,906 | 1,364 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total depreciation and amortization
|
$ | 111,574 | $ | 106,930 | $ | 115,118 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) |
Excludes depreciation and amortization recognized by Ohio Gathering due to equity method accounting.
|
| (2) |
Includes the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in Other revenues.
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Cash paid for capital expenditures (1):
|
||||||||||||
|
Utica Shale
|
$ | 3,902 | $ | 5,719 | $ | 22,921 | ||||||
|
Williston Basin
|
30,861 | 25,202 | 17,309 | |||||||||
|
DJ Basin
|
80,487 | 64,920 | 7,150 | |||||||||
|
Permian Basin
|
44,955 | 83,823 | 56,020 | |||||||||
|
Piceance Basin
|
1,946 | 7,887 | 16,564 | |||||||||
|
Barnett Shale (2)
|
184 | 1,370 | 569 | |||||||||
|
Marcellus Shale
|
693 | 1,030 | 641 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total reportable segment capital expenditures
|
163,028 | 189,951 | 121,174 | |||||||||
|
Corporate and Other
|
19,263 | 10,635 | 3,041 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total cash paid for capital expenditures
|
$ | 182,291 | $ | 200,586 | $ | 124,215 | ||||||
|
|
|
|
|
|
|
|||||||
| (1) |
Excludes cash paid for capital expenditures by Ohio Gathering due to equity method accounting.
|
| (2) |
For the year ended December 31, 2019, the amount includes sales tax reimbursements of $1.1 million.
|
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Reportable segment adjusted EBITDA
|
||||||||||||
|
Utica Shale
|
$ | 29,292 | $ | 30,285 | $ | 34,011 | ||||||
|
Ohio Gathering
|
39,126 | 39,969 | 41,246 | |||||||||
|
Williston Basin
|
69,437 | 76,701 | 66,413 | |||||||||
|
DJ Basin
|
18,668 | 7,558 | 6,624 | |||||||||
|
Permian Basin
|
(879 | ) | (1,200 | ) | — | |||||||
|
Piceance Basin
|
98,765 | 111,042 | 111,113 | |||||||||
|
Barnett Shale
|
43,043 | 43,268 | 46,232 | |||||||||
|
Marcellus Shale
|
20,051 | 24,267 | 23,888 | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total of reportable segments’ measures of profit
|
$ | 317,503 | $ | 331,890 | $ | 329,527 | ||||||
|
|
|
|
|
|
|
|||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Reconciliation of (loss) income before income taxes and loss from equity method investees to total of reportable segments’ measures of profit:
|
||||||||||||
|
(Loss) income before income taxes and loss from equity method investees
|
$ | (54,644 | ) | $ | 45,575 | $ | (134,187 | ) | ||||
|
Add:
|
||||||||||||
|
Corporate and Other expense
|
44,808 | 45,131 | 40,803 | |||||||||
|
Interest expense
|
91,966 | 82,830 | 88,701 | |||||||||
|
Early extinguishment of debt
|
— | — | 22,039 | |||||||||
|
Depreciation and amortization
|
111,574 | 106,930 | 115,118 | |||||||||
|
Proportional adjusted EBITDA for equity method
investees
|
39,126 | 39,969 | 41,246 | |||||||||
|
Adjustments related to MVC shortfall payments
|
3,476 | (3,632 | ) | (41,373 | ) | |||||||
|
Adjustments related to capital reimbursement activity
|
(2,156 | ) | (427 | ) | — | |||||||
|
Unit-based and noncash compensation
|
8,171 | 8,328 | 7,951 | |||||||||
|
(Gain) loss on asset sales, net
|
(1,536 | ) | — | 527 | ||||||||
|
Long-lived asset impairment
|
60,507 | 7,186 | 188,702 | |||||||||
|
Goodwill impairment
|
16,211 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total of reportable segments’ measures of profit
|
$ | 317,503 | $ | 331,890 | $ | 329,527 | ||||||
|
|
|
|
|
|
|
|||||||
|
Year ended December 31, 2019
|
||||||||||||||||
|
Williston
Basin
|
Piceance
Basin
|
Barnett
Shale
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Adjustments related to expected MVC shortfall payments:
|
$ | — | $ | (103 | ) | $ | 3,579 | $ | 3,476 | |||||||
|
Year ended December 31, 2018
|
||||||||||||||||
|
Williston
Basin
|
Piceance
Basin
|
Barnett
Shale
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Adjustments related to expected MVC shortfall payments:
|
$ | — | $ | 10 | $ | (3,642 | ) | $ | (3,632 | ) | ||||||
|
Year Ended December 31, 2017
|
||||||||||||||||
|
Williston
Basin
|
Piceance
Basin
|
Barnett
Shale
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Adjustments related to MVC shortfall payments:
|
||||||||||||||||
|
Net change in deferred revenue for MVC shortfall payments
|
$ | (37,693 | ) | $ | (3,065 | ) | $ | — | $ | (40,758 | ) | |||||
|
Expected MVC shortfall adjustments
|
— | (3 | ) | (612 | ) | (615 | ) | |||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Total adjustments related to MVC shortfall payments
|
$ | (37,693 | ) | $ | (3,068 | ) | $ | (612 | ) | $ | (41,373 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
|
December 31, 2019
|
December 31, 2018
|
|||||||
|
(In thousands)
|
||||||||
|
Gathering and processing systems and related equipment
|
$ | 2,182,950 | $ | 2,155,325 | ||||
|
Construction in progress
|
78,716 | 137,920 | ||||||
|
Land and line fill
|
10,137 | 11,748 | ||||||
|
Other
|
54,595 | 47,319 | ||||||
|
|
|
|
|
|||||
|
Total
|
2,326,398 | 2,352,312 | ||||||
|
Less accumulated depreciation
|
443,909 | 388,213 | ||||||
|
|
|
|
|
|||||
|
Property, plant and equipment, net
|
$ | 1,882,489 | $ | 1,964,099 | ||||
|
|
|
|
|
|||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Long-lived asset impairment:
|
||||||||||||
|
Williston Basin
|
$ | 10 | $ | 3,972 | $ | 101,961 | ||||||
|
Piceance Basin
|
14,162 | 1,004 | 697 | |||||||||
|
DJ Basin
|
34,913 | 9 | — | |||||||||
|
Barnett Shale
|
9,629 | — | — | |||||||||
|
Utica Shale
|
— | 1,440 | 878 | |||||||||
|
Permian Basin
|
726 | 761 | — | |||||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Depreciation expense
|
$ | 78,489 | $ | 74,674 | $ | 75,382 | ||||||
|
Capitalized interest
|
6,974 | 8,497 | 2,579 | |||||||||
|
December 31, 2019
|
||||||||||||
|
Gross carrying
amount |
Accumulated
amortization |
Net
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Favorable gas gathering contracts
|
$ | 24,195 | $ | (15,125 | ) | $ | 9,070 | |||||
|
Contract intangibles
|
278,448 | (169,549 | ) | 108,899 | ||||||||
|
Rights-of-way
|
157,175 | (42,866 | ) | 114,309 | ||||||||
|
|
|
|
|
|
|
|||||||
|
Total intangible assets
|
$ | 459,818 | $ | (227,540 | ) | $ | 232,278 | |||||
|
|
|
|
|
|
|
|||||||
|
December 31, 2018
|
||||||||||||
|
Gross carrying
amount |
Accumulated
amortization |
Net
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Favorable gas gathering contracts
|
$ | 24,195 | $ | (13,905 | ) | $ | 10,290 | |||||
|
Contract intangibles
|
278,448 | (143,962 | ) | 134,486 | ||||||||
|
Rights-of-way
|
166,209 | (37,569 | ) | 128,640 | ||||||||
|
|
|
|
|
|
|
|||||||
|
Total intangible assets
|
$ | 468,852 | $ | (195,436 | ) | $ | 273,416 | |||||
|
|
|
|
|
|
|
|||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Amortization expense – favorable gas gathering contracts
|
$ | (1,220 | ) | $ | (1,555 | ) | $ | (1,555 | ) | |||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Amortization expense – contract intangibles
|
$ | 25,587 | $ | 26,141 | $ | 34,202 | ||||||
|
Amortization expense –
rights-of-way
|
6,278 | 6,448 | 6,153 | |||||||||
|
Intangible assets
|
||||
|
(In thousands)
|
||||
|
2020
|
$ | 31,901 | ||
|
2021
|
28,209 | |||
|
2022
|
25,142 | |||
|
2023
|
25,088 | |||
|
2024
|
14,917 | |||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Accumulated goodwill impairment:
|
||||||||||||
|
Piceance Basin
|
$ | 45,478 | $ | 45,478 | $ | 45,478 | ||||||
|
Williston Basin
|
257,572 | 257,572 | 257,572 | |||||||||
|
Marcellus Shale
|
16,211 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Total accumulated goodwill impairment
|
$ | 319,261 | $ | 303,050 | $ | 303,050 | ||||||
|
2019
|
2018
|
|||||||
|
(In thousands)
|
||||||||
|
Investment in Ohio Gathering, December 31
|
$ | 275,000 | $ | 649,250 | ||||
|
December cash distributions
|
2,700 | 2,736 | ||||||
|
Impairment loss (1)
|
232,521 | 5,652 | ||||||
|
Loss contingency
|
— | 2,040 | ||||||
|
Basis difference
|
— | (116,832 | ) | |||||
|
|
|
|
|
|||||
|
Investment in Ohio Gathering, net of basis difference, November 30
|
$ | 510,221 | $ | 542,846 | ||||
|
|
|
|
|
|||||
| (1) |
Amount is comprised of (i) a $329.7 million impairment of our equity method investment in Ohio Gathering; (ii) the
write-off
of our basis difference of ($103.5) million in Ohio Gathering as a result of the impairment in our equity method investment in Ohio Gathering; and (iii) a $6.3 million impairment of long-lived assets in OCC.
|
|
November 30, 2019
|
November 30, 2018
|
|||||||||||||||
|
OGC
|
OCC
|
OGC
|
OCC
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Current assets
|
$ | 41,972 | $ | 2,187 | $ | 37,403 | $ | 3,716 | ||||||||
|
Noncurrent assets
|
1,281,171 | 28,323 | 1,262,253 | 27,203 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Total assets
|
$ | 1,323,143 | $ | 30,510 | $ | 1,299,656 | $ | 30,919 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Current liabilities
|
$ | 21,798 | $ | 4,016 | $ | 19,903 | $ | 3,912 | ||||||||
|
Noncurrent liabilities
|
4,113 | 6,683 | 3,688 | 8,807 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Total liabilities
|
$ | 25,911 | $ | 10,699 | $ | 23,591 | $ | 12,719 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Twelve months ended
November 30, 2019
|
Twelve months ended
November 30, 2018
|
Twelve months ended
November 30, 2017
|
||||||||||||||||||||||
|
OGC
|
OCC
|
OGC
|
OCC
|
OGC
|
OCC
|
|||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
|
Total revenues
|
$ | 142,138 | $ | 8,601 | $ | 142,398 | $ | 10,177 | $ | 140,679 | $ | 8,607 | ||||||||||||
|
Total operating expenses
|
108,234 | 38,815 | 136,722 | 9,053 | 111,897 | 8,298 | ||||||||||||||||||
|
Net income (loss)
|
33,897 | (30,214 | ) | 5,670 | 498 | 28,785 | (907 | ) | ||||||||||||||||
| • |
To the extent that a customer’s throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer’s MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).
|
| • |
To the extent that a customer’s throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs.
|
| • |
To the extent that certain of our customers’ throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.
|
|
Utica Shale
|
Williston
Basin |
DJ
Basin
|
Piceance
Basin
|
Barnett
Shale |
Marcellus
Shale |
Total
current |
||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||
|
Current deferred revenue, January 1, 2018
|
$ | 18 | $ | 1,017 | $ | 358 | $ | 7,038 | $ | 1,619 | $ | 38 | $ | 10,088 | ||||||||||||||
|
Additions
|
18 | 1,744 | 943 | 21,955 | 1,651 | 96 | 26,407 | |||||||||||||||||||||
|
Less revenue recognized
|
18 | 1,347 | 562 | 21,377 | 1,628 | 96 | 25,028 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Current deferred revenue, December 31, 2018
|
18 | 1,414 | 739 | 7,616 | 1,642 | 38 | 11,467 | |||||||||||||||||||||
|
Additions
|
18 | 2,262 | 5,165 | 16,211 | 1,632 | 38 | 25,326 | |||||||||||||||||||||
|
Less revenue recognized
|
18 | 1,743 | 3,044 | 16,813 | 1,644 | 38 | 23,300 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Current deferred revenue, December 31, 2019
|
$ | 18 | $ | 1,933 | $ | 2,860 | $ | 7,014 | $ | 1,630 | $ | 38 | $ | 13,493 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Utica Shale
|
Williston
Basin |
DJ
Basin
|
Piceance
Basin
|
Barnett
Shale |
Marcellus
Shale |
Total
noncurrent |
||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||
|
Noncurrent deferred, revenue, January 1, 2018
|
$ | 39 | $ | 4,215 | $ | 4,505 | $ | 18,219 | $ | 8,217 | $ | 333 | $ | 35,528 | ||||||||||||||
|
Additions
|
— | 1,851 | 3,720 | 7,869 | 3,062 | — | 16,502 | |||||||||||||||||||||
|
Less reclassification to current
deferred revenue
|
18 | 1,673 | 941 | 8,146 | 1,651 | 97 | 12,526 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Noncurrent deferred revenue, December 31, 2018
|
21 | 4,393 | 7,284 | 17,942 | 9,628 | 236 | 39,504 | |||||||||||||||||||||
|
Additions
|
— | 1,940 | 5,470 | 6,104 | 1,579 | — | 15,093 | |||||||||||||||||||||
|
Less reclassification to current
deferred revenue
|
18 | 2,699 | 5,165 | 6,336 | 1,632 | 38 | 15,888 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Noncurrent deferred revenue, December 31, 2019
|
$ | 3 | $ | 3,634 | $ | 7,589 | $ | 17,710 | $ | 9,575 | $ | 198 | $ | 38,709 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
December 31, 2019
|
December 31, 2018
|
|||||||
|
(In thousands)
|
||||||||
|
Summit Holdings’ variable rate senior
secured
Revolving Credit Facility
(
4.55% at December 31, 2019 and 5.03% at December 31, 2018) due May 2022
|
$ | 677,000 | $ | 466,000 | ||||
|
Summit Holdings’ 5.5% senior unsecured notes due August 2022
|
300,000 | 300,000 | ||||||
|
Less unamortized debt issuance costs (1)
|
(1,686 | ) | (2,362 | ) | ||||
|
Summit Holdings’ 5.75% senior unsecured notes due April 2025
|
500,000 | 500,000 | ||||||
|
Less unamortized debt issuance costs (1)
|
(5,015 | ) | (5,907 | ) | ||||
|
SMP Holdings’ variable rate senior secured term loan
(
7.80% at December 31, 2019 and 8.52% at December 31, 2018) due May 2022
|
161,500 | 226,750 | ||||||
|
Less unamortized debt issuance costs (1)
|
(3,974 | ) | (5,701 | ) | ||||
|
|
|
|
|
|||||
|
Total debt
|
1,627,825 | 1,478,780 | ||||||
|
Less current portion
|
5,546 | 14,500 | ||||||
|
|
|
|
|
|||||
|
Total long-term debt
|
$ | 1,622,279 | $ | 1,464,280 | ||||
|
|
|
|
|
|||||
| (1) |
Issuance costs are being amortized over the life of the
Term Loan B
and Senior Notes.
|
|
2020
|
$ | — | ||
|
2021
|
— | |||
|
2022
|
1,138,500 | |||
|
2023
|
— | |||
|
2024
|
— | |||
|
Thereafter
|
500,000 | |||
|
|
|
|||
|
Total long-term debt
|
$ | 1,638,500 | ||
|
|
|
|
December 31, 2019
|
December 31, 2018
|
|||||||||||||||
|
Carrying
value
|
Estimated
fair value
(Level 2)
|
Carrying
value
|
Estimated
fair value
(Level 2)
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Summit Holdings 5.5% Senior Notes ($300.0 million principal)
|
$ | 298,314 | $ | 266,750 | $ | 297,638 | $ | 286,625 | ||||||||
|
Summit Holdings 5.75% Senior Notes ($500.0 million principal)
|
494,985 | 382,708 | 494,093 | 455,208 | ||||||||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
Per-unit
distributions to unitholders
|
$ | 1.4375 | $ | 2.300 | $ | 2.300 | ||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands, except
per-unit
amounts)
|
||||||||||||
|
Numerator for basic and diluted EPU:
|
||||||||||||
|
Allocation of net (loss) income among limited partner interests:
|
||||||||||||
|
Net (loss) income attributable to limited partners
|
$ | (184,451 | ) | $ | 31,546 | $ | (183,411 | ) | ||||
|
Less net income attributable to Series A Preferred Units
|
28,500 | 28,500 | 3,563 | |||||||||
|
Less net income attributable to Subsidiary Series A Preferred Units
|
58 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Net (loss) income attributable to common limited partners
|
$ | (213,009 | ) | $ | 3,046 | $ | (186,974 | ) | ||||
|
|
|
|
|
|
|
|||||||
|
Denominator for basic and diluted EPU:
|
||||||||||||
|
Weighted-average common units outstanding – basic (1)
|
45,319 | 45,319 | 45,319 | |||||||||
|
Effect of nonvested phantom units
|
— | 311 | — | |||||||||
|
|
|
|
|
|
|
|||||||
|
Weighted-average common units outstanding – diluted
|
45,319 | 45,630 | 45,319 | |||||||||
|
|
|
|
|
|
|
|||||||
|
(Loss) earnings per limited partner unit:
|
||||||||||||
|
Common unit – basic
|
$ | (4.70 | ) | $ | 0.07 | $ | (4.13 | ) | ||||
|
Common unit – diluted
|
$ | (4.70 | ) | $ | 0.07 | $ | (4.13 | ) | ||||
|
Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU
|
175 | 2 | 42 | |||||||||
| (1) |
As a result of the GP
Buy-In
Transaction, our historical results are those of Summit Investments. The number of common units of 45.3 million represents those of Summit Investments and has been used for the earnings per unit calculations presented herein.
|
|
Units
|
Weighted-average
grant date fair value |
|||||||
|
Nonvested phantom units, January 1, 2017
|
691,955 | $ | 19.59 | |||||
|
Phantom units granted
|
371,972 | 22.50 | ||||||
|
Phantom units vested
|
(293,222 | ) | 24.76 | |||||
|
Phantom units forfeited
|
(21,431 | ) | 20.07 | |||||
|
|
|
|||||||
|
Nonvested phantom units, December 31, 2017
|
749,274 | 20.07 | ||||||
|
Phantom units granted
|
515,358 | 15.25 | ||||||
|
Phantom units vested
|
(359,016 | ) | 22.39 | |||||
|
Phantom units forfeited
|
(41,492 | ) | 17.27 | |||||
|
|
|
|||||||
|
Nonvested phantom units, December 31, 2018
|
864,124 | 17.11 | ||||||
|
Phantom units granted
|
1,913,099 | 6.48 | ||||||
|
Phantom units vested
|
(602,617 | ) | 16.78 | |||||
|
Phantom units forfeited
|
(68,611 | ) | 12.87 | |||||
|
|
|
|||||||
|
Nonvested phantom units, December 31, 2019
|
2,105,995 | $ | 7.69 | |||||
|
|
|
|||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Intrinsic value of vested LTIP awards
|
$ | 5,940 | $ | 5,393 | $ | 6,657 | ||||||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
SMLP LTIP unit-based compensation
|
$ | 8,171 | $ | 8,328 | $ | 7,951 | ||||||
|
December 31,
|
||||
|
2019
|
||||
|
(In thousands)
|
||||
|
ROU assets
|
||||
|
Operating
|
$ | 3,580 | ||
|
Finance
|
3,159 | |||
|
|
|
|||
| $ | 6,739 | |||
|
Lease liabilities, current
|
||||
|
Operating
|
$ | 1,221 | ||
|
Finance
|
1,246 | |||
|
|
|
|||
| $ | 2,467 | |||
|
Lease liabilities, noncurrent
|
||||
|
Operating
|
$ | 2,513 | ||
|
Finance
|
676 | |||
|
|
|
|||
| $ | 3,189 | |||
|
Year ended December 31, 2019
|
||||
|
(In thousands)
|
||||
|
Lease cost
|
||||
|
Finance lease cost:
|
||||
|
Amortization of ROU assets (included in depreciation and amortization)
|
$ | 1,559 | ||
|
Interest on lease liabilities (included in interest expense)
|
102 | |||
|
Operating lease cost (included in general and administrative expense)
|
3,345 | |||
|
|
|
|||
| $ | 5,006 | |||
|
Twelve months ended
|
||||
|
December 31, 2019
|
||||
|
(In thousands)
|
||||
|
Other information
|
||||
|
Cash paid for amounts included in the measurement of lease liabilities
|
||||
|
Operating cash outflows from operating leases
|
$ | 3,396 | ||
|
Operating cash outflows from finance leases
|
102 | |||
|
Financing cash outflows from finance leases
|
1,873 | |||
|
ROU assets obtained in exchange for new operating lease liabilities
|
1,218 | |||
|
ROU assets obtained in exchange for new finance lease liabilities
|
1,350 | |||
|
Weighted-average remaining lease term (years) - operating leases
|
5.8 | |||
|
Weighted-average remaining lease term (years) - finance leases
|
2.0 | |||
|
Weighted-average discount rate - operating leases
|
5 | % | ||
|
Weighted-average discount rate - finance leases
|
4 | % | ||
|
Year ended December 31,
|
||||||||||||
|
2019
|
2018
|
2017
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Lease expense
|
$ | 4,038 | $ | 4,108 | $ | 3,963 | ||||||
|
December 31, 2019
|
||||||||
|
(In thousands)
|
||||||||
|
Operating
|
Finance
|
|||||||
|
2020
|
$ | 1,705 | $ | 1,299 | ||||
|
2021
|
1,004 | 616 | ||||||
|
2022
|
551 | 76 | ||||||
|
2023
|
408 | — | ||||||
|
2024
|
240 | — | ||||||
|
2025
|
153 | — | ||||||
|
Thereafter
|
742 | — | ||||||
|
|
|
|
|
|||||
|
Total future minimum lease payments
|
$ | 4,803 | $ | 1,991 | ||||
|
|
|
|
|
|||||
|
December 31,
|
||||
|
2018
|
||||
|
(In thousands)
|
||||
|
2019
|
$ | 3,133 | ||
|
2020
|
1,018 | |||
|
2021
|
550 | |||
|
2022
|
506 | |||
|
2023
|
373 | |||
|
Thereafter
|
621 | |||
|
|
|
|||
|
Total future minimum lease payments
|
$ | 6,201 | ||
|
|
|
|||
|
December 31,
|
||||
|
2018
|
||||
|
(In thousands)
|
||||
|
2019
|
$ | 1,473 | ||
|
2020
|
902 | |||
|
2021
|
174 | |||
|
|
|
|||
|
Total finance lease obligations
|
2,549 | |||
|
Less: Amounts representing interest
|
(104 | ) | ||
|
|
|
|||
|
Net present value of finance lease obligations
|
2,445 | |||
|
Less: Amount representing current portion (included in Other current liabilities)
|
(1,406 | ) | ||
|
|
|
|||
|
Finance lease obligations, less current portion (included in Other noncurrent liabilities)
|
$ | 1,039 | ||
|
|
|
|||
|
Total
|
||||
|
(In thousands)
|
||||
|
Accrued environmental remediation, January 1, 2018
|
$ | 5,344 | ||
|
Payments made
|
(3,808 | ) | ||
|
Additional accruals
|
4,100 | |||
|
|
|
|||
|
Accrued environmental remediation, December 31, 2018
|
$ | 5,636 | ||
|
Payments made
|
(2,284 | ) | ||
|
Additional accruals
|
1,299 | |||
|
|
|
|||
|
Accrued environmental remediation, December 31, 2019
|
$ | 4,651 | ||
|
|
|
|||
| • |
Employee-related costs — we reorganized our workforce and eliminated redundant or unneeded positions. In connection with the workforce restructuring, we expect to incur severance, benefits and other employee related costs of approximately $6.0 million to be incurred over the twelve months following December 31, 2019. During the fiscal year ended December 31, 2019, we expensed approximately $3.8 million primarily related to severance, redundant salaries, certain bonuses and other employee benefits in connection with our plan. As of December 31, 2019, we had approximately $2.7 million included in current liabilities for these costs.
|
| • |
Consultants — we engaged third-party consulting firms to assist in the evaluation of the Company’s cost structure, to help formulate the plan to implement the project, and to provide project management services for certain project initiatives. During the fiscal year ended December 31, 2019, we expensed approximately $1.2 million related to these services. As of December 31, 2019, we had approximately $0.6 million included in current liabilities for these costs. We expect to incur an additional $0.2 million related to consulting costs to be incurred over the next twelve months following December 31, 2019.
|
|
Quarter ended
|
||||||||||||||||
|
December 31, 2019
|
September 30, 2019
|
June 30, 2019
|
March 31, 2019
|
|||||||||||||
|
(In thousands, except
per-unit
amounts)
|
||||||||||||||||
|
Total revenues
|
$ | 112,247 | $ | 100,187 | $ | 99,686 | $ | 131,408 | ||||||||
|
Net (loss) income attributable to SMLP
|
$ | (345,345 | ) | $ | (11,129 | ) | $ | 3,028 | $ | (40,280 | ) | |||||
|
Less net loss attributable to noncontrolling interest
|
(172,024 | ) | (10,340 | ) | (1,341 | ) | (25,570 | ) | ||||||||
|
Less net income attributable to Series A Preferred Units
|
7,125 | 7,125 | 7,125 | 7,125 | ||||||||||||
|
Less net income attributable to Subsidiary Series A Preferred Units
|
58 | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Net loss attributable to common limited partners
|
$ | (180,504 | ) | $ | (7,914 | ) | $ | (2,756 | ) | $ | (21,835 | ) | ||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Loss per limited partner unit:
|
||||||||||||||||
|
Common unit - basic
|
$ | (3.98 | ) | $ | (0.17 | ) | $ | (0.06 | ) | $ | (0.48 | ) | ||||
|
Common unit - diluted
|
$ | (3.98 | ) | $ | (0.17 | ) | $ | (0.06 | ) | $ | (0.48 | ) | ||||
|
Quarter ended
|
||||||||||||||||
|
December 31, 2018
|
September 30, 2018
|
June 30, 2018
|
March 31, 2018
|
|||||||||||||
|
(In thousands, except
per-unit
amounts)
|
||||||||||||||||
|
Total revenues
|
$ | 133,671 | $ | 127,479 | $ | 128,183 | $ | 117,320 | ||||||||
|
Net (loss) income attributable to SMLP
|
$ | (3,401 | ) | $ | 14,353 | $ | 11,861 | $ | 11,507 | |||||||
|
Less net income (loss) attributable to noncontrolling interest
|
18,535 | 30,453 | (37,712 | ) | (8,502 | ) | ||||||||||
|
Less net income attributable to Series A Preferred Units
|
7,125 | 7,125 | 7,125 | 7,125 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Net (loss) income attributable to common limited partners
|
$ | (29,061 | ) | $ | (23,225 | ) | $ | 42,448 | $ | 12,884 | ||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
(Loss) earnings per limited partner unit:
|
||||||||||||||||
|
Common unit - basic
|
$ | (0.64 | ) | $ | (0.51 | ) | $ | 0.94 | $ | 0.28 | ||||||
|
Common unit - diluted
|
$ | (0.64 | ) | $ | (0.51 | ) | $ | 0.93 | $ | 0.28 | ||||||
|
Item 1.
|
Financial Statements.
|
|
March 31,
2020 |
December 31,
2019 |
|||||||
|
(In thousands, except unit amounts)
|
||||||||
|
Assets
|
||||||||
|
Current assets:
|
||||||||
|
Cash and cash equivalents
|
$ | 73,324 | $ | 9,530 | ||||
|
Restricted cash
|
4,057 | 27,392 | ||||||
|
Accounts receivable
|
78,948 | 97,418 | ||||||
|
Other current assets
|
4,471 | 5,521 | ||||||
|
|
|
|
|
|||||
|
Total current assets
|
160,800 | 139,861 | ||||||
|
Property, plant and equipment, net
|
1,870,083 | 1,882,489 | ||||||
|
Intangible assets, net
|
224,076 | 232,278 | ||||||
|
Investment in equity method investees
|
363,578 | 309,728 | ||||||
|
Other noncurrent assets
|
7,760 | 9,742 | ||||||
|
|
|
|
|
|||||
|
Total assets
|
$ | 2,626,297 | $ | 2,574,098 | ||||
|
|
|
|
|
|||||
|
Liabilities and Capital
|
||||||||
|
Current liabilities:
|
||||||||
|
Trade accounts payable
|
$ | 22,307 | $ | 24,415 | ||||
|
Accrued expenses
|
11,201 | 11,339 | ||||||
|
Deferred revenue
|
14,318 | 13,493 | ||||||
|
Ad valorem taxes payable
|
3,696 | 8,477 | ||||||
|
Accrued interest
|
15,405 | 12,346 | ||||||
|
Accrued environmental remediation
|
2,016 | 1,725 | ||||||
|
Other current liabilities
|
8,686 | 12,206 | ||||||
|
Current portion of long-term debt
|
7,800 | 5,546 | ||||||
|
|
|
|
|
|||||
|
Total current liabilities
|
85,429 | 89,547 | ||||||
|
Long-term debt
|
1,641,065 | 1,622,279 | ||||||
|
Noncurrent deferred revenue
|
43,045 | 38,709 | ||||||
|
Noncurrent accrued environmental remediation
|
2,618 | 2,926 | ||||||
|
Other noncurrent liabilities
|
8,044 | 7,951 | ||||||
|
|
|
|
|
|||||
|
Total liabilities
|
1,780,201 | 1,761,412 | ||||||
|
Commitments and contingencies (Note 15)
|
||||||||
|
Mezzanine Capital
|
||||||||
|
Subsidiary Series A Preferred Units (66,002 units issued and outstanding at March 31, 2020 and 30,058 units issued and outstanding at December 31, 2019)
|
62,341 | 27,450 | ||||||
|
Partners’ Capital
|
||||||||
|
Series A Preferred Units (300,000 units issued and outstanding at March 31, 2020 and December 31, 2019)
|
300,741 | 293,616 | ||||||
|
Common limited partner capital
|
300,801 | 305,550 | ||||||
|
Noncontrolling interest
|
182,213 | 186,070 | ||||||
|
|
|
|
|
|||||
|
Total partners’ capital
|
783,755 | 785,236 | ||||||
|
|
|
|
|
|||||
|
Total liabilities, mezzanine capital and partners’ capital
|
$ | 2,626,297 | $ | 2,574,098 | ||||
|
|
|
|
|
|||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands, except per-unit amounts)
|
||||||||
|
Revenues:
|
||||||||
|
Gathering services and related fees
|
$ | 83,792 | $ | 86,964 | ||||
|
Natural gas, NGLs and condensate sales
|
13,780 | 37,928 | ||||||
|
Other revenues
|
7,331 | 6,516 | ||||||
|
|
|
|
|
|||||
|
Total revenues
|
104,903 | 131,408 | ||||||
|
|
|
|
|
|||||
|
Costs and expenses:
|
||||||||
|
Cost of natural gas and NGLs
|
8,225 | 31,759 | ||||||
|
Operation and maintenance
|
21,811 | 24,222 | ||||||
|
General and administrative
|
16,561 | 18,385 | ||||||
|
Depreciation and amortization
|
29,666 | 27,764 | ||||||
|
Transaction costs
|
11 | 2,337 | ||||||
|
Loss (gain) on asset sales, net
|
115 | (961 | ) | |||||
|
Long-lived asset impairment
|
3,821 | 44,951 | ||||||
|
|
|
|
|
|||||
|
Total costs and expenses
|
80,210 | 148,457 | ||||||
|
|
|
|
|
|||||
|
Other (expense) income
|
(427 | ) | 209 | |||||
|
Interest expense
|
(23,828 | ) | (22,742 | ) | ||||
|
|
|
|
|
|||||
|
Income (loss) before income taxes and income (loss) from equity method investees
|
438 | (39,582 | ) | |||||
|
Income tax benefit (expense)
|
13 | (257 | ) | |||||
|
Income (loss) from equity method investees
|
3,311 | (441 | ) | |||||
|
|
|
|
|
|||||
|
Net income (loss)
|
$ | 3,762 | $ | (40,280 | ) | |||
|
|
|
|
|
|||||
|
Less:
|
||||||||
|
Net loss attributable to noncontrolling interest
|
(1,881 | ) | (25,570 | ) | ||||
|
|
|
|
|
|||||
|
Net income (loss) attributable to limited partners
|
5,643 | (14,710 | ) | |||||
|
Net income attributable to Series A Preferred Units
|
7,125 | 7,125 | ||||||
|
Net income attributable to Subsidiary Series A Preferred Units
|
945 | — | ||||||
|
|
|
|
|
|||||
|
Net loss attributable to common limited partners
|
$ | (2,427 | ) | $ | (21,835 | ) | ||
|
|
|
|
|
|||||
|
Loss per limited partner unit:
|
||||||||
|
Common unit – basic
|
$ | (0.05 | ) | $ | (0.48 | ) | ||
|
Common unit – diluted
|
$ | (0.05 | ) | $ | (0.48 | ) | ||
|
Weighted-average limited partner units outstanding:
|
||||||||
|
Common units – basic
|
45,319 | 45,319 | ||||||
|
Common units – diluted
|
45,319 | 45,319 | ||||||
|
Noncontrolling Interest
|
||||||||||||||||
|
Series A
Preferred Units |
Common
Noncontrolling Interests (1) |
Partners’ Capital
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Partners’ capital, January 1, 2020
|
$ | 293,616 | $ | 186,070 | $ | 305,550 | $ | 785,236 | ||||||||
|
Net income (loss)
|
7,125 | (1,881 | ) | (2,427 | ) | 2,817 | ||||||||||
|
Net cash distributions to SMLP unitholders
|
— | (6,037 | ) | — | (6,037 | ) | ||||||||||
|
Unit-based compensation
|
— | 2,723 | — | 2,723 | ||||||||||||
|
Effect of common unit issuances under SMLP LTIP
|
— | 2,322 | (2,322 | ) | — | |||||||||||
|
Tax withholdings and associated payments on vested SMLP LTIP awards
|
— | (984 | ) | — | (984 | ) | ||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, March 31, 2020
|
$ | 300,741 | $ | 182,213 | $ | 300,801 | $ | 783,755 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Noncontrolling Interest
|
||||||||||||||||
|
Series A
Preferred Units |
Common
Noncontrolling Interests (1) |
Partners’ Capital
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Partners’ capital, January 1, 2019
|
$ | 293,616 | $ | 554,472 | $ | 543,479 | $ | 1,391,567 | ||||||||
|
Net income (loss)
|
7,125 | (25,570 | ) | (21,835 | ) | (40,280 | ) | |||||||||
|
Net cash distributions to SMLP unitholders
|
— | (27,374 | ) | — | (27,374 | ) | ||||||||||
|
Unit-based compensation
|
— | 2,526 | — | 2,526 | ||||||||||||
|
Effect of common unit issuances under SMLP LTIP
|
— | 2,387 | (2,387 | ) | — | |||||||||||
|
Tax withholdings and associated payments on vested SMLP LTIP awards
|
— | (2,524 | ) | — | (2,524 | ) | ||||||||||
|
Conversion of noncontrolling interest related to cancellation of subsidiary incentive distribution rights
|
— | (48,203 | ) | 48,203 | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
|
Partners’ capital, March 31, 2019
|
$ | 300,741 | $ | 455,714 | $ | 567,460 | $ | 1,323,915 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (1) |
Prior to the GP
Buy-In
Transaction, common noncontrolling interests reported by Summit Investments included equity interests in SMLP that were not owned by Summit Investments.
|
|
March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Cash flows from operating activities:
|
||||||||
|
Net income (loss)
|
$ | 3,762 | $ | (40,280 | ) | |||
|
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
|
||||||||
|
Depreciation and amortization
|
29,900 | 28,153 | ||||||
|
Noncash lease expense
|
473 | 765 | ||||||
|
Amortization of debt issuance costs
|
1,582 | 1,549 | ||||||
|
Unit-based and noncash compensation
|
2,723 | 2,526 | ||||||
|
(Income) loss from equity method investees
|
(3,311 | ) | 441 | |||||
|
Distributions from equity method investees
|
7,494 | 8,583 | ||||||
|
Loss (gain) on asset sales, net
|
115 | (961 | ) | |||||
|
Long-lived asset impairment
|
3,821 | 44,951 | ||||||
|
Changes in operating assets and liabilities:
|
||||||||
|
Accounts receivable
|
18,470 | 4,675 | ||||||
|
Trade accounts payable
|
3,973 | 274 | ||||||
|
Accrued expenses
|
(138 | ) | (1,274 | ) | ||||
|
Deferred revenue, net
|
5,161 | 2,323 | ||||||
|
Ad valorem taxes payable
|
(4,781 | ) | (6,184 | ) | ||||
|
Accrued interest
|
3,059 | 3,153 | ||||||
|
Accrued environmental remediation, net
|
(17 | ) | (548 | ) | ||||
|
Other, net
|
(2,085 | ) | (2,953 | ) | ||||
|
|
|
|
|
|||||
|
Net cash provided by operating activities
|
70,201 | 45,193 | ||||||
|
|
|
|
|
|||||
|
Cash flows from investing activities:
|
||||||||
|
Capital expenditures
|
(18,583 | ) | (60,848 | ) | ||||
|
Proceeds from asset sale (net of cash of $1,475 for the period ended March 31, 2019)
|
— | 89,461 | ||||||
|
Investment in equity method investee
|
(58,033 | ) | — | |||||
|
Other, net
|
217 | (120 | ) | |||||
|
|
|
|
|
|||||
|
Net cash (used in) provided by investing activities
|
(76,399 | ) | 28,493 | |||||
|
|
|
|
|
|||||
|
March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Cash flows from financing activities:
|
||||||||
|
Net cash Distributions to noncontrolling interest SMLP unitholders
|
(6,037 | ) | (27,374 | ) | ||||
|
Borrowings under Revolving Credit Facility
|
55,000 | 69,000 | ||||||
|
Repayments under Revolving Credit Facility
|
(34,000 | ) | (101,000 | ) | ||||
|
Repayments under SMP Holdings term loan
|
(750 | ) | (12,250 | ) | ||||
|
Debt issuance costs
|
(101 | ) | (179 | ) | ||||
|
Proceeds from issuance of Series A preferred units, net of costs
|
33,946 | — | ||||||
|
Other, net
|
(1,401 | ) | (2,968 | ) | ||||
|
|
|
|
|
|||||
|
Net cash provided by (used in) financing activities
|
46,657 | (74,771 | ) | |||||
|
|
|
|
|
|||||
|
Net change in cash, cash equivalents and restricted cash
|
40,459 | (1,085 | ) | |||||
|
Cash, cash equivalents and restricted cash, beginning of period
|
36,922 | 16,173 | ||||||
|
|
|
|
|
|||||
|
Cash, cash equivalents and restricted cash, end of period (1)
|
$ | 77,381 | $ | 15,088 | ||||
|
|
|
|
|
|||||
|
Supplemental cash flow disclosures:
|
||||||||
|
Cash interest paid
|
$ | 19,660 | $ | 19,932 | ||||
|
Less capitalized interest
|
491 | 1,915 | ||||||
|
|
|
|
|
|||||
|
Interest paid (net of capitalized interest)
|
$ | 19,169 | $ | 18,017 | ||||
|
|
|
|
|
|||||
|
Cash paid for taxes
|
$ | — | $ | — | ||||
|
Noncash investing and financing activities
|
||||||||
|
Capital expenditures in trade accounts payable
(period-end
accruals)
|
$ | 13,765 | $ | 23,389 | ||||
|
Right-of-use
|
— | 5,448 | ||||||
| (1) |
A reconciliation of cash, cash equivalents and restricted cash to the consolidated balance sheets follow:
|
|
March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Cash and cash equivalents
|
$ | 73,324 | $ | 15,088 | ||||
|
Restricted cash
|
4,057 | — | ||||||
|
|
|
|
|
|||||
|
Total cash, cash equivalents and restricted cash
|
$ | 77,381 | $ | 15,088 | ||||
|
|
|
|
|
|||||
| • |
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
|
| • |
Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;
|
| • |
Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
|
| • |
Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;
|
| • |
Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming;
|
| • |
Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico;
|
| • |
Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas;
|
| • |
Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado;
|
| • |
DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and
|
| • |
Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia.
|
| • |
ASU
No. 2018-13
Fair Value Measurement (“ASU
2018-13”).
ASU
2018-13
updates the disclosure requirements on fair value measurements including new disclosures for the changes in unrealized gains and losses for the period included in other comprehensive income for recurring Level 3 fair value measurements held at the end of the reporting period and the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. ASU
2018-13
modifies existing disclosures including clarifying the measurement uncertainty disclosure. ASU
2018-13
removes certain existing disclosure requirements including the amount and reasons for transfers between Level 1 and Level 2 fair value measurements and the policy for the timing of transfer between levels. The adoption of ASU
2018-13
on January 1, 2020 did not have a material impact on our unaudited condensed consolidated financial statement disclosures.
|
| • |
ASU
No. 2016-13
Financial Instruments – Credit Losses (“ASU
2016-13”).
ASU
2016-13
requires the use of a current expected loss model for financial assets measured at amortized cost and certain
off-balance
sheet credit exposures. Under this model, entities will be required to estimate the lifetime expected credit losses on such instruments based on historical experience, current conditions, and reasonable and supportable forecasts. This amended guidance also expands the disclosure requirements to enable users of financial statements to understand an entity’s assumptions, models and methods for estimating expected credit losses. The changes are effective for annual and interim periods beginning after December 15, 2019, and amendments should be applied using a modified retrospective approach. The adoption of ASU
2016-13
on January 1, 2020 did not have a material impact on our unaudited condensed consolidated financial statements or disclosures.
|
| • |
ASU
No. 2020-04
Reference Rate Reform (“ASU
2020-04”).
ASU
2020-04
provides optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform on financial reporting. The amendments in ASU
2020-04
are effective as of March 12, 2020 through December 31, 2022. We are currently evaluating the provisions of ASU
2020-04
to determine its impact on our unaudited condensed consolidated financial statements and disclosures.
|
|
2020
|
2021
|
2022
|
2023
|
2024
|
Thereafter
|
|||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 86,916 | $ | 102,127 | $ | 84,736 | $ | 66,693 | $ | 50,608 | $ | 58,672 | ||||||||||||
|
Reportable Segments
|
||||||||||||||||||||||||||||||||||||||||
|
Three months ended March 31, 2020
|
||||||||||||||||||||||||||||||||||||||||
|
Utica
Shale |
Williston
Basin |
DJ
Basin |
Permian
Basin |
Piceance
Basin |
Barnett
Shale |
Marcellus
Shale |
Total
reportable segments |
All other
segments |
Total
|
|||||||||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||||||||||
|
Major products / services lines
|
||||||||||||||||||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 6,962 | $ | 23,797 | $ | 6,855 | $ | 2,311 | $ | 27,189 | $ | 10,443 | $ | 6,235 | $ | 83,792 | $ | — | $ | 83,792 | ||||||||||||||||||||
|
Natural gas, NGLs and condensate sales
|
— | 4,324 | 70 | 4,512 | 1,003 | 3,871 | — | 13,780 | — | 13,780 | ||||||||||||||||||||||||||||||
|
Other revenues
|
— | 3,142 | 1,034 | 187 | 1,065 | 1,260 | — | 6,688 | 643 | 7,331 | ||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
Total
|
$ | 6,962 | $ | 31,263 | $ | 7,959 | $ | 7,010 | $ | 29,257 | $ | 15,574 | $ | 6,235 | $ | 104,260 | $ | 643 | $ | 104,903 | ||||||||||||||||||||
|
Reportable Segments
|
||||||||||||||||||||||||||||||||||||||||
|
Three months ended March 31, 2019
|
||||||||||||||||||||||||||||||||||||||||
|
Utica
Shale |
Williston
Basin |
DJ
Basin |
Permian
Basin |
Piceance
Basin |
Barnett
Shale |
Marcellus
Shale |
Total
reportable segments |
All other
segments |
Total
|
|||||||||||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||||||||||||||
|
Major products / services lines
|
||||||||||||||||||||||||||||||||||||||||
|
Gathering services and related fees
|
$ | 7,495 | $ | 25,706 | $ | 3,724 | $ | 366 | $ | 31,840 | $ | 13,025 | $ | 6,197 | $ | 88,353 | $ | (1,389 | ) | $ | 86,964 | |||||||||||||||||||
|
Natural gas, NGLs and condensate sales
|
— | 5,585 | 85 | 4,221 | 2,302 | 604 | — | 12,797 | 25,131 | 37,928 | ||||||||||||||||||||||||||||||
|
Other revenues
|
— | 2,908 | 1,007 | 32 | 1,138 | 1,656 | — | 6,741 | (225 | ) | 6,516 | |||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||
|
Total
|
$ | 7,495 | $ | 34,199 | $ | 4,816 | $ | 4,619 | $ | 35,280 | $ | 15,285 | $ | 6,197 | $ | 107,891 | $ | 23,517 | $ | 131,408 | ||||||||||||||||||||
|
March 31, 2020
|
December 31, 2019
|
|||||||
|
(In thousands)
|
||||||||
|
Contract assets, beginning of period
|
$ | 3,902 | $ | 8,755 | ||||
|
Additions
|
13,877 | 18,077 | ||||||
|
Transfers out
|
(425 | ) | (22,930 | ) | ||||
|
|
|
|
|
|||||
|
Contract assets, end of period
|
$ | 17,354 | $ | 3,902 | ||||
| • |
the Utica Shale, which is served by Summit Utica;
|
| • |
Ohio Gathering, which includes our ownership interest in OGC and OCC;
|
| • |
the Williston Basin, which is served by Polar and Divide and Bison Midstream;
|
| • |
the DJ Basin, which is served by Niobrara G&P;
|
| • |
the Permian Basin, which is served by Summit Permian;
|
| • |
the Piceance Basin, which is served by Grand River;
|
| • |
the Barnett Shale, which is served by DFW Midstream; and
|
| • |
the Marcellus Shale, which is served by Mountaineer Midstream.
|
|
March 31, 2020
|
December 31, 2019
|
|||||||
|
(In thousands)
|
||||||||
|
Assets (1):
|
||||||||
|
Utica Shale
|
$ | 205,341 | $ | 206,368 | ||||
|
Ohio Gathering
|
271,268 | 275,000 | ||||||
|
Williston Basin
|
452,684 | 452,152 | ||||||
|
DJ Basin
|
200,473 | 205,308 | ||||||
|
Permian Basin
|
184,043 | 185,708 | ||||||
|
Piceance Basin
|
622,403 | 631,140 | ||||||
|
Barnett Shale
|
345,248 | 350,638 | ||||||
|
Marcellus Shale
|
184,279 | 184,631 | ||||||
|
|
|
|
|
|||||
|
Total reportable segment assets
|
2,465,739 | 2,490,945 | ||||||
|
Corporate and Other
|
160,558 | 83,153 | ||||||
|
|
|
|
|
|||||
|
Total assets
|
$ | 2,626,297 | $ | 2,574,098 | ||||
|
|
|
|
|
|||||
| (1) |
At March 31, 2020, Corporate and Other included $92.3 million relating to our investment in Double E (included in the Investment in equity method investees caption of the unaudited condensed consolidated balance sheet). At December 31, 2019, Corporate and Other included $34.7 million relating to our investment in Double E.
|
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Revenues (1):
|
||||||||
|
Utica Shale
|
$ | 6,962 | $ | 7,495 | ||||
|
Williston Basin
|
31,263 | 34,199 | ||||||
|
DJ Basin
|
7,959 | 4,816 | ||||||
|
Permian Basin
|
7,010 | 4,619 | ||||||
|
Piceance Basin
|
29,257 | 35,280 | ||||||
|
Barnett Shale
|
15,574 | 15,285 | ||||||
|
Marcellus Shale
|
6,235 | 6,197 | ||||||
|
|
|
|
|
|||||
|
Total reportable segments revenue
|
104,260 | 107,891 | ||||||
|
Corporate and Other
|
643 | 26,838 | ||||||
|
Eliminations
|
— | (3,321 | ) | |||||
|
|
|
|
|
|||||
|
Total revenues
|
$ | 104,903 | $ | 131,408 | ||||
|
|
|
|
|
|||||
| (1) |
Excludes revenues earned by Ohio Gathering due to equity method accounting.
|
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
Percentage of total revenues (1):
|
||||||||
|
Counterparty A - Piceance Basin
|
11 | % | * | |||||
| (1) |
Excludes revenues earned by Ohio Gathering due to equity method accounting.
|
| * |
Less than 10%
|
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Depreciation and amortization (1):
|
||||||||
|
Utica Shale
|
$ | 1,927 | $ | 1,908 | ||||
|
Williston Basin
|
6,495 | 5,436 | ||||||
|
DJ Basin
|
1,527 | 799 | ||||||
|
Permian Basin
|
1,345 | 1,072 | ||||||
|
Piceance Basin
|
11,298 | 11,791 | ||||||
|
Barnett Shale (2)
|
4,032 | 4,330 | ||||||
|
Marcellus Shale
|
2,300 | 2,283 | ||||||
|
|
|
|
|
|||||
|
Total reportable segment depreciation and amortization
|
28,924 | 27,619 | ||||||
|
Corporate and Other
|
976 | 534 | ||||||
|
|
|
|
|
|||||
|
Total depreciation and amortization
|
$ | 29,900 | $ | 28,153 | ||||
|
|
|
|
|
|||||
| (1) |
Excludes depreciation and amortization recognized by Ohio Gathering due to equity method accounting.
|
| (2) |
Includes the amortization expense associated with our favorable gas gathering contracts as reported in Other revenues.
|
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Cash paid for capital expenditures (1):
|
||||||||
|
Utica Shale
|
$ | 909 | $ | 101 | ||||
|
Williston Basin
|
4,943 | 8,023 | ||||||
|
DJ Basin
|
6,298 | 28,356 | ||||||
|
Permian Basin
|
3,281 | 7,057 | ||||||
|
Piceance Basin
|
346 | 1,226 | ||||||
|
Barnett Shale (2)
|
657 | (118 | ) | |||||
|
Marcellus Shale
|
422 | 102 | ||||||
|
|
|
|
|
|||||
|
Total reportable segment capital expenditures
|
16,856 | 44,747 | ||||||
|
Corporate and Other
|
1,727 | 16,101 | ||||||
|
|
|
|
|
|||||
|
Total cash paid for capital expenditures
|
$ | 18,583 | $ | 60,848 | ||||
|
|
|
|
|
|||||
| (1) |
Excludes cash paid for capital expenditures by Ohio Gathering due to equity method accounting.
|
| (2) |
For the three months ended March 31, 2019, the amount includes sales tax reimbursements of $1.1 million.
|
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Reportable segment adjusted EBITDA
|
||||||||
|
Utica Shale
|
$ | 5,928 | $ | 6,193 | ||||
|
Ohio Gathering
|
7,939 | 9,210 | ||||||
|
Williston Basin
|
16,192 | 18,734 | ||||||
|
DJ Basin
|
5,911 | 2,673 | ||||||
|
Permian Basin
|
1,581 | (550 | ) | |||||
|
Piceance Basin
|
23,557 | 25,999 | ||||||
|
Barnett Shale
|
8,760 | 11,374 | ||||||
|
Marcellus Shale
|
5,320 | 5,142 | ||||||
|
|
|
|
|
|||||
|
Total of reportable segments’ measures of profit
|
$ | 75,188 | $ | 78,775 | ||||
|
|
|
|
|
|||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Reconciliation of income (loss) before income taxes and income (loss) from equity method investees to total of reportable segments’ measures of profit:
|
||||||||
|
Income (loss) before income taxes and income (loss) from equity method investees
|
$ | 438 | $ | (39,582 | ) | |||
|
Add:
|
||||||||
|
Corporate and Other expense
|
12,077 | 16,650 | ||||||
|
Interest expense
|
23,828 | 22,742 | ||||||
|
Depreciation and amortization
|
29,900 | 28,153 | ||||||
|
Proportional adjusted EBITDA for equity method investees
|
7,939 | 9,210 | ||||||
|
Adjustments related to MVC shortfall payments
|
(5,442 | ) | (4,199 | ) | ||||
|
Adjustments related to capital reimbursement activity
|
(211 | ) | (715 | ) | ||||
|
Unit-based and noncash compensation
|
2,723 | 2,526 | ||||||
|
Loss (gain) on asset sales, net
|
115 | (961 | ) | |||||
|
Long-lived asset impairment
|
3,821 | 44,951 | ||||||
|
|
|
|
|
|||||
|
Total of reportable segments’ measures of profit
|
$ | 75,188 | $ | 78,775 | ||||
|
|
|
|
|
|||||
|
Three months ended March 31, 2020
|
||||||||||||||||
|
Williston
Basin
|
Piceance
Basin
|
Barnett
Shale
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Adjustments related to expected MVC shortfall payments:
|
$ | (5,665 | ) | $ | 223 | $ | — | $ | (5,442 | ) | ||||||
|
Three months ended March 31, 2019
|
||||||||||||||||
|
Williston
Basin
|
Piceance
Basin
|
Barnett
Shale
|
Total
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Adjustments related to expected MVC shortfall payments:
|
$ | (5,549 | ) | $ | (103 | ) | $ | 1,453 | $ | (4,199 | ) | |||||
|
March 31, 2020
|
December 31, 2019
|
|||||||
|
(In thousands)
|
||||||||
|
Gathering and processing systems and related equipment
|
$ | 2,193,225 | $ | 2,182,950 | ||||
|
Construction in progress
|
73,040 | 78,716 | ||||||
|
Land and line fill
|
10,440 | 10,137 | ||||||
|
Other
|
59,014 | 54,595 | ||||||
|
|
|
|
|
|||||
|
Total
|
2,335,719 | 2,326,398 | ||||||
|
Less accumulated depreciation
|
465,636 | 443,909 | ||||||
|
|
|
|
|
|||||
|
Property, plant and equipment, net
|
$ | 1,870,083 | $ | 1,882,489 | ||||
|
|
|
|
|
|||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Depreciation expense
|
$ | 21,698 | $ | 19,820 | ||||
|
Capitalized interest
|
491 | 1,915 | ||||||
|
March 31, 2020
|
||||||||||||
|
Gross carrying
amount |
Accumulated
amortization |
Net
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Favorable gas gathering contracts
|
$ | 24,195 | $ | (15,359 | ) | $ | 8,836 | |||||
|
Contract intangibles
|
278,448 | (175,973 | ) | 102,475 | ||||||||
|
Rights-of-way
|
157,175 | (44,410 | ) | 112,765 | ||||||||
|
|
|
|
|
|
|
|||||||
|
Total intangible assets
|
$ | 459,818 | $ | (235,742 | ) | $ | 224,076 | |||||
|
|
|
|
|
|
|
|||||||
|
December 31, 2019
|
||||||||||||
|
Gross carrying
amount |
Accumulated
amortization |
Net
|
||||||||||
|
(In thousands)
|
||||||||||||
|
Favorable gas gathering contracts
|
$ | 24,195 | $ | (15,125 | ) | $ | 9,070 | |||||
|
Contract intangibles
|
278,448 | (169,549 | ) | 108,899 | ||||||||
|
Rights-of-way
|
157,175 | (42,866 | ) | 114,309 | ||||||||
|
|
|
|
|
|
|
|||||||
|
Total intangible assets
|
$ | 459,818 | $ | (227,540 | ) | $ | 232,278 | |||||
|
|
|
|
|
|
|
|||||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Amortization expense – favorable gas gathering contracts
|
$ | (234 | ) | $ | (389 | ) | ||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Amortization expense – contract intangibles
|
$ | 6,424 | $ | 6,397 | ||||
|
Amortization expense –
rights-of-way
|
1,544 | 1,547 | ||||||
|
Intangible assets
|
||||
|
(In thousands)
|
||||
|
2020
|
$ | 23,926 | ||
|
2021
|
28,209 | |||
|
2022
|
25,142 | |||
|
2023
|
25,088 | |||
|
2024
|
14,917 | |||
|
Investment in Ohio Gathering, March 31, 2020
|
$ | 271,268 | ||
|
March cash distributions
|
1,875 | |||
|
Basis difference
|
223,151 | |||
|
|
|
|||
|
Investment in Ohio Gathering February 29, 2020
|
$ | 496,294 | ||
|
|
|
|
Three months ended
February 29, 2020
|
Three months ended
February 28, 2019
|
|||||||||||||||
|
OGC
|
OCC
|
OGC
|
OCC
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Total revenues
|
$ | 30,068 | $ | 2,727 | $ | 33,466 | $ | 2,266 | ||||||||
|
Total operating expenses
|
25,750 | 30,855 | 25,487 | 2,973 | ||||||||||||
|
Net income (loss)
|
4,311 | (28,128 | ) | 7,972 | (707 | ) | ||||||||||
|
Utica
Shale |
Williston
Basin |
DJ Basin
|
Piceance
Basin
|
Barnett
Shale |
Marcellus
Shale |
Total
current |
||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||
|
Current deferred revenue, January 1, 2020
|
$ | 18 | $ | 1,933 | $ | 2,860 | $ | 7,014 | $ | 1,630 | $ | 38 | $ | 13,493 | ||||||||||||||
|
Additions
|
2 | 483 | 2,123 | 1,547 | 396 | 9 | 4,560 | |||||||||||||||||||||
|
Less revenue recognized
|
5 | 483 | 1,285 | 1,544 | 409 | 9 | 3,735 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Current deferred revenue, March 31, 2020
|
$ | 15 | $ | 1,933 | $ | 3,698 | $ | 7,017 | $ | 1,617 | $ | 38 | $ | 14,318 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Utica
Shale |
Williston
Basin |
DJ
Basin |
Piceance
Basin
|
Barnett
Shale |
Marcellus
Shale |
Total
noncurrent |
||||||||||||||||||||||
|
(In thousands)
|
||||||||||||||||||||||||||||
|
Noncurrent deferred revenue, January 1, 2020
|
$ | 3 | $ | 3,634 | $ | 7,589 | $ | 17,710 | $ | 9,575 | $ | 198 | $ | 38,709 | ||||||||||||||
|
Additions
|
425 | 3,522 | 3,263 | 1,304 | 382 | — | 8,896 | |||||||||||||||||||||
|
Less reclassification to current deferred revenue
|
2 | 483 | 2,123 | 1,547 | 396 | 9 | 4,560 | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Noncurrent deferred revenue, March 31, 2020
|
$ | 426 | $ | 6,673 | $ | 8,729 | $ | 17,467 | $ | 9,561 | $ | 189 | $ | 43,045 | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
March 31, 2020
|
December 31, 2019
|
|||||||
|
(In thousands)
|
||||||||
|
Summit Holdings’ variable rate senior secured Revolving Credit Facility (3.74% at March 31, 2020 and 4.55% at December 31, 2019) due May 2022
|
$ | 698,000 | $ | 677,000 | ||||
|
Summit Holdings’ 5.5% senior unsecured notes due August 2022
|
300,000 | 300,000 | ||||||
|
Less unamortized debt issuance costs (1)
|
(1,521 | ) | (1,686 | ) | ||||
|
Summit Holdings’ 5.75% senior unsecured notes due April 2025
|
500,000 | 500,000 | ||||||
|
Less unamortized debt issuance costs (1)
|
(4,763 | ) | (5,015 | ) | ||||
|
SMP Holdings’ variable rate senior secured term loan (7.00% at March 31, 2020 and 7.80% at December 31, 2019) due May 2022
|
160,750 | 161,500 | ||||||
|
Less unamortized debt issuance costs (1)
|
(3,601 | ) | (3,974 | ) | ||||
|
|
|
|
|
|||||
|
Total debt
|
1,648,865 | 1,627,825 | ||||||
|
Less current portion
|
7,800 | 5,546 | ||||||
|
|
|
|
|
|||||
|
Total long-term debt
|
$ | 1,641,065 | $ | 1,622,279 | ||||
|
|
|
|
|
|||||
| (1) |
Issuance costs are being amortized over the life of the Term Loan B and Senior Notes.
|
|
March 31, 2020
|
December 31, 2019
|
|||||||||||||||
|
Carrying
value
|
Estimated
fair value
(Level 2)
|
Carrying
value
|
Estimated
fair value
(Level 2)
|
|||||||||||||
|
(In thousands)
|
||||||||||||||||
|
Summit Holdings 5.5% Senior Notes ($300.0 million principal)
|
$ | 298,479 | $ | 58,875 | $ | 298,314 | $ | 266,750 | ||||||||
|
Summit Holdings 5.75% Senior Notes ($500.0 million principal)
|
495,237 | 53,125 | 494,985 | 382,708 | ||||||||||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
Per-unit
distributions to unitholders
|
$ | 0.125 | $ | 0.575 | ||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands, except per-unit amounts)
|
||||||||
|
Numerator for basic and diluted EPU:
|
||||||||
|
Allocation of net income (loss) among limited partner interests:
|
||||||||
|
Net income (loss) attributable to limited partners
|
$ | 5,643 | $ | (14,710 | ) | |||
|
Less net income attributable to Series A Preferred Units
|
7,125 | 7,125 | ||||||
|
Less net income attributable to Subsidiary Series A Preferred Units
|
945 | — | ||||||
|
|
|
|
|
|||||
|
Net loss attributable to common limited partners
|
$ | (2,427 | ) | $ | (21,835 | ) | ||
|
|
|
|
|
|||||
|
Denominator for basic and diluted EPU:
|
||||||||
|
Weighted-average common units outstanding – basic and diluted (1)
|
45,319 | 45,319 | ||||||
|
|
|
|
|
|||||
|
Loss per limited partner unit:
|
||||||||
|
Common unit – basic
|
$ | (0.05 | ) | $ | (0.48 | ) | ||
|
Common unit – diluted
|
$ | (0.05 | ) | $ | (0.48 | ) | ||
|
Nonvested anti-dilutive phantom units excluded from the calculation of diluted EPU
|
1,889 | 34 | ||||||
| (1) |
As a result of the GP
Buy-In
Transaction, our historical results are those of Summit Investments. The number of common units of 45.3 million represents those of Summit Investments and has been used for the earnings per unit calculations presented herein.
|
| • |
In March 2020, we granted 3,811,301 phantom units and associated distribution equivalent rights to employees in connection with our annual incentive compensation award cycle. These awards had a grant date fair value of $0.55 and vest ratably over a three-year period.
|
| • |
In March 2020, we also issued 549,450 common units to our three independent directors in connection with their annual compensation plan.
|
| • |
During the three months ended March 31, 2020, 418,999 phantom units vested.
|
| • |
In March 2020, we increased the number of common units authorized under the SMLP LTIP to 15,000,000 common units and extended the term of the SMLP LTIP for 10 years.
|
| • |
As of March 31, 2020, approximately 6.9 million common units remained available for future issuance under the SMLP LTIP.
|
|
March 31, 2020
|
December 31, 2019
|
|||||||
|
(In thousands)
|
||||||||
|
ROU assets
|
||||||||
|
Operating
|
$ | 4,306 | $ | 3,580 | ||||
|
Finance
|
2,649 | 3,159 | ||||||
|
|
|
|
|
|||||
| $ | 6,955 | $ | 6,739 | |||||
|
Lease liabilities, current
|
||||||||
|
Operating
|
$ | 967 | $ | 1,221 | ||||
|
Finance
|
1,023 | 1,246 | ||||||
|
|
|
|
|
|||||
| $ | 1,990 | $ | 2,467 | |||||
|
Lease liabilities, noncurrent
|
||||||||
|
Operating
|
$ | 3,482 | $ | 2,513 | ||||
|
Finance
|
483 | 676 | ||||||
|
|
|
|
|
|||||
| $ | 3,965 | $ | 3,189 | |||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Lease cost
|
||||||||
|
Finance lease cost:
|
||||||||
|
Amortization of ROU assets (included in depreciation and amortization)
|
$ | 352 | $ | 368 | ||||
|
Interest on lease liabilities (included in interest expense)
|
18 | 23 | ||||||
|
Operating lease cost (included in general and administrative expense)
|
772 | 832 | ||||||
|
|
|
|
|
|||||
| $ | 1,142 | $ | 1,223 | |||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Other information
|
||||||||
|
Cash paid for amounts included in the measurement of lease liabilities
|
||||||||
|
Operating cash outflows from operating leases
|
$ | 708 | $ | 821 | ||||
|
Operating cash outflows from finance leases
|
18 | 23 | ||||||
|
Financing cash outflows from finance leases
|
417 | 445 | ||||||
|
ROU assets obtained in exchange for new operating lease liabilities
|
1,199 | — | ||||||
|
ROU assets obtained in exchange for new finance lease liabilities
|
— | 693 | ||||||
|
Weighted-average remaining lease term (years) - operating leases
|
6.0 | 3.5 | ||||||
|
Weighted-average remaining lease term (years) - finance leases
|
2.0 | 2.0 | ||||||
|
Weighted-average discount rate - operating leases
|
5 | % | 5 | % | ||||
|
Weighted-average discount rate - finance leases
|
4 | % | 4 | % | ||||
|
Three months ended March 31,
|
||||||||
|
2020
|
2019
|
|||||||
|
(In thousands)
|
||||||||
|
Lease expense
|
$ | 953 | $ | 990 | ||||
|
March 31, 2020
|
||||||||
|
(In thousands)
|
||||||||
|
Operating
|
Finance
|
|||||||
|
2020
|
$ | 1,046 | $ | 873 | ||||
|
2021
|
1,125 | 606 | ||||||
|
2022
|
883 | 76 | ||||||
|
2023
|
741 | — | ||||||
|
2024
|
555 | — | ||||||
|
2025
|
464 | — | ||||||
|
Thereafter
|
742 | — | ||||||
|
|
|
|
|
|||||
|
Total future minimum lease payments
|
$ | 5,556 | $ | 1,555 | ||||
|
|
|
|
|
|||||
|
December 31, 2019
|
||||||||
|
(In thousands)
|
||||||||
|
Operating
|
Finance
|
|||||||
|
2020
|
$ | 1,705 | $ | 1,299 | ||||
|
2021
|
1,004 | 616 | ||||||
|
2022
|
551 | 76 | ||||||
|
2023
|
408 | — | ||||||
|
2024
|
240 | — | ||||||
|
2025
|
153 | — | ||||||
|
Thereafter
|
742 | — | ||||||
|
|
|
|
|
|||||
|
Total future minimum lease payments
|
$ | 4,803 | $ | 1,991 | ||||
|
|
|
|
|
|||||
|
Total
|
||||
|
(In thousands)
|
||||
|
Accrued environmental remediation, January 1, 2020
|
$ | 4,651 | ||
|
Payments made
|
(17 | ) | ||
|
|
|
|||
|
Accrued environmental remediation, March 31, 2020
|
$ | 4,634 | ||
|
|
|
|||
| • |
Employee-related costs — We reorganized our workforce and eliminated redundant or unneeded positions. In connection with the workforce restructuring, we expect to incur severance, benefits and other employee related costs of approximately $4.1 million over the next nine months following March 31, 2020. During the three months ended March 31, 2020, we expensed approximately $1.9 million primarily related to severance, redundant salaries, certain bonuses and other employee benefits in connection with our plan. As of March 31, 2020, cash payments were made of approximately $2.1 million and we had approximately $2.4 million included in the Other current liabilities caption on the unaudited condensed consolidated balance sheets for these costs, which we expect to pay over the remainder of the year.
|
| • |
Consultants — We engaged third-party consulting firms to assist in the evaluation of the Partnership’s cost structure, to help formulate the plan to implement the project, and to provide project management services for certain project initiatives. During the three months ended March 31, 2020, we expensed approximately $0.9 million related to these services. As of March 31, 2020, cash payments of approximately $1.1 million were made and we had approximately $0.4 million included in the Other current liabilities caption on the unaudited condensed consolidated balance sheets for these costs, which we expect to pay over the remainder of the year. We expect to incur an additional $0.2 million related to consulting costs to be incurred over the next nine months following March 31, 2020.
|
EXHIBIT 99.5
EXPLANATORY NOTE
On May 28, 2020, Summit Midstream Partners, LP, a Delaware limited partnership (the “Partnership”), closed on a Purchase Agreement (the “Purchase Agreement”) with affiliates of Energy Capital Partners II, LLC, a Delaware limited liability company (“ECP”) to acquire all the outstanding limited liability company interests of Summit Midstream Partners, LLC, a Delaware limited liability company (“Summit Investments”). We refer to the transactions contemplated by the Purchase Agreement as the “GP Buy-In Transaction.”
The May 2020 acquisition of Summit Investments was a transaction between entities under common control. As a result, the Partnership recast its financial statements for the period that the entities were under common control by Summit Investments to retrospectively reflect the May 2020 acquisition. Under GAAP, the GP Buy-In Transaction was deemed a transaction among entities under common control with a change in reporting entity. Although the Partnership is the surviving entity for legal purposes, Summit Investments is the surviving entity for accounting purposes; therefore, the historical financial results of the Partnership prior to the GP Buy-In Transaction presented below are those of Summit Investments. Prior to the GP Buy-In Transaction, Summit Investments controlled the Partnership and the Partnership’s financial statements were consolidated into Summit Investments.
The information in this Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations includes periods prior to the GP Buy-In Transaction. Consequently, the Partnership’s consolidated financial statements and this Item 2 have been retrospectively recast for all periods presented in order to present the financial results of the surviving entity for accounting purposes.
EX 99.5-1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries for the periods since December 31, 2019. As a result, the following discussion should be read in conjunction with Item 1, “Financial Statements” and Item 8, “Financial Statements and Supplementary Data” of this Current Report on Form 8-K. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements. Actual results may differ materially from those contained in any forward-looking statements.
This MD&A comprises the following sections:
| • |
Overview |
| • |
Trends and Outlook |
| • |
How We Evaluate Our Operations |
| • |
Results of Operations |
| • |
Liquidity and Capital Resources |
| • |
Critical Accounting Estimates |
| • |
Forward-Looking Statements |
Overview
We are a value-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in unconventional resource basins, primarily shale formations, in the continental United States.
We classify our midstream energy infrastructure assets into two categories:
| • |
Core Focus Areas – core producing areas of basins in which we expect our gathering systems to experience greater long-term growth, driven by our customers’ ability to generate more favorable returns and support sustained drilling and completion activity in varying commodity price environments. In the near-term, we expect to concentrate the majority of our capital expenditures in our Core Focus Areas. Our Utica Shale, Ohio Gathering, Williston Basin, DJ Basin and Permian Basin reportable segments (as described below) comprise our Core Focus Areas. |
| • |
Legacy Areas – production basins in which we expect volume throughput on our gathering systems to experience relatively lower long-term growth compared to our Core Focus Areas, given that our customers require relatively higher commodity prices to support drilling and completion activities in these basins. Upstream production served by our gathering systems in our Legacy Areas is generally more mature, as compared to our Core Focus Areas, and the decline rates for volume throughput on our gathering systems in the Legacy Areas are typically lower as a result. We expect to continue to reduce our near-term capital expenditures in these Legacy Areas. Our Piceance Basin, Barnett Shale and Marcellus Shale reportable segments (as described below) comprise our Legacy Areas. |
EX 99.5-2
We are the owner-operator of or have significant ownership interests in the following gathering and transportation systems, which comprise our Core Focus Areas:
| • |
Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; |
| • |
Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio; |
| • |
Polar and Divide, a crude oil and produced water gathering system and transmission pipeline operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
| • |
Bison Midstream, an associated natural gas gathering system operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota; |
| • |
Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado and southeastern Wyoming; |
| • |
Summit Permian, an associated natural gas gathering and processing system operating in the northern Delaware Basin, which includes the Wolfcamp and Bone Spring formations, in southeastern New Mexico; and |
| • |
Double E, a 1.35 Bcf/d natural gas transmission pipeline that is under development and will provide transportation service from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. |
We are the owner-operator of the following gathering systems, which comprise our Legacy Areas:
| • |
Grand River, a natural gas gathering and processing system operating in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado; |
| • |
DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and |
| • |
Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia. |
For additional information on our organization and systems, see Notes 1 and 4 to the unaudited condensed consolidated financial statements.
Our financial results are driven primarily by volume throughput across our gathering systems and by expense management. We generate the majority of our revenues from the gathering, compression, treating and processing services that we provide to our customers. A majority of the volumes that we gather, compress, treat and/or process have a fixed-fee rate structure which enhances the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from the following activities that directly expose us to fluctuations in commodity prices: (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds or other processing arrangements with certain of our customers on the Bison Midstream, Grand River and Summit Permian systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. During the three months ended March 31, 2020, these additional activities accounted for approximately 13% of total revenues.
We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs, if any, ensure that we will earn a minimum amount of revenue.
EX 99.5-3
The following table presents certain consolidated and reportable segment financial data. For additional information on our reportable segments, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.
| Three months ended March 31, | ||||||||
| 2020 | 2019 | |||||||
| (In thousands) | ||||||||
|
Net income (loss) |
$ | 3,762 | $ | (40,280 | ) | |||
|
Reportable segment adjusted EBITDA |
||||||||
|
Utica Shale |
$ | 5,928 | $ | 6,193 | ||||
|
Ohio Gathering |
7,939 | 9,210 | ||||||
|
Williston Basin |
16,192 | 18,734 | ||||||
|
DJ Basin |
5,911 | 2,673 | ||||||
|
Permian Basin |
1,581 | (550 | ) | |||||
|
Piceance Basin |
23,557 | 25,999 | ||||||
|
Barnett Shale |
8,760 | 11,374 | ||||||
|
Marcellus Shale |
5,320 | 5,142 | ||||||
|
Net cash provided by operating activities |
$ | 70,201 | $ | 45,193 | ||||
|
Capital expenditures (1) |
18,583 | 60,848 | ||||||
|
Investment in equity method investee |
58,033 | — | ||||||
|
Net cash distributions to noncontrolling interest SMLP unitholders |
$ | 6,037 | $ | 27,374 | ||||
|
Net borrowings (repayments) under Revolving Credit Facility |
21,000 | (32,000 | ) | |||||
|
Repayments under SMP Holdings term loan |
(750 | ) | (12,250 | ) | ||||
|
Proceeds from issuance of Subsidiary Series A preferred units, net of costs (2) |
33,946 | — | ||||||
Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.
| (1) |
See “Liquidity and Capital Resources” herein and Note 4 to the unaudited condensed consolidated financial statements for additional information on capital expenditures. |
| (2) |
Reflects proceeds from the issuance of Subsidiary Series A Preferred Units. |
Three months ended March 31, 2020. The following items are reflected in our financial results:
| • |
In March 2020, in connection with the cancellation of a compressor station project in the DJ Basin due to delays in customer drilling plans, we recorded an impairment charge of $3.6 million for the related soft project costs. |
Three months ended March 31, 2019. The following items are reflected in our financial results:
| • |
In March 2019, we sold the Tioga Midstream system to affiliates of Hess Infrastructure Partners LP for a combined cash purchase price of approximately $90 million and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the carrying value for Tioga Midstream at closing. The gain is included in the Gain on asset sales, net caption on the unaudited condensed consolidated statement of operations. The financial results of Tioga Midstream (a component of the Williston Basin reportable segment) are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through March 22, 2019. |
| • |
In March 2019, certain events occurred which indicated that certain long-lived assets in the DJ Basin and Barnett Shale reporting segments could be impaired. Consequently, we performed a recoverability assessment of certain assets within these reporting segments. In the DJ Basin, we determined certain processing plant assets related to our existing 20 MMcf/d plant would no longer be operational due to our expansion plans for the Niobrara G&P system and we recorded an impairment charge of $34.7 million related to these assets. In the Barnett Shale, we determined certain compressor station assets would be shut down and de-commissioned beginning in the second quarter of 2019 and we recorded an impairment charge of $10.2 million related to these assets. |
EX 99.5-4
Trends and Outlook
Our business has been, and we expect our future business to continue to be, affected by the following key trends:
| • |
Natural gas, NGL and crude oil supply and demand dynamics; |
| • |
Production from U.S. shale plays; |
| • |
Capital markets availability and cost of capital; |
| • |
Shifts in operating costs and inflation; and |
| • |
Ongoing impact of the COVID-19 pandemic and reduced demand and prices for oil. |
We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our customers, employees, supply chain and distribution network. While COVID-19 did not have a material adverse effect on our reported results for the first quarter of 2020, only one month of the quarter was affected by COVID-19 and if the current conditions continue, subsequent quarters may reflect these conditions for a full quarter. We are unable to predict the ultimate impact that COVID-19 and related factors may have on our business, future results of operations, financial position or cash flows. The extent to which our operations may be impacted by the COVID-19 pandemic will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.
In response to the COVID-19 pandemic, we have modified our business practices, including restricting employee travel, modifying employee work locations, implementing social distancing and enhanced sanitary measures in our facilities. Many of our suppliers, vendors and service providers have made similar modifications. The resources available to employees working remotely may not enable them to maintain the same level of productivity and efficiency, and these and other employees may face additional demands on their time. Our increased reliance on remote access to our information systems increases our exposure to potential cybersecurity breaches. We may take further actions as government authorities require or recommend or as we determine to be in the best interests of our employees, customers, partners and suppliers. There is no certainty that such measures will be sufficient to mitigate the risks posed by the virus, in which case our employees may become sick, our ability to perform critical functions could be harmed, and we may be unable to respond to the needs of our business. The resumption of normal business operations after such interruptions may be delayed or constrained by lingering effects of COVID-19 on our suppliers, third-party service providers, and/or customers.
In addition, the COVID-19 pandemic has significantly reduced the global demand for oil and natural gas. This significant decline in demand has been met with a sharp decline in oil prices following the announcement of price reductions and production increases in March 2020 by members of the Organization of Petroleum Exporting Countries, or OPEC, and other foreign, oil-exporting countries. The resulting supply and demand imbalance is having disruptive impacts on the oil and natural gas exploration and production industry and on other industries that serve exploration and production companies. These industry conditions, coupled with those resulting from the COVID-19 pandemic, could lead to significant global economic contraction generally and in our industry in particular. Although OPEC agreed in April to cut production, the responses of oil and gas producers to the lower demand for, and price of, natural gas, NGLs and crude oil are constantly evolving and remain uncertain. Such responses could cause our pipelines and storage tanks and other third-party storage facilities to reach capacity, thereby forcing producers to experience shut-ins or look to alternative methods of transportation for their products.
Over the past several weeks we have collaborated extensively with our customer base regarding reductions and delays to drilling and completion activities in light of the current commodity price backdrop and COVID-19 pandemic. Given further deterioration of market conditions in March and April and based on recently updated production forecasts and revised 2020 development plans from our customers, we currently expect our 2020 results to be affected by decreased drilling activity and the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin and DJ Basin reportable segments. Accordingly, we now expect 2020 total capital expenditures to range from of $30 million to $50 million.
EX 99.5-5
The full extent to which our operations may be impacted by the COVID-19 pandemic and reduced demand and pricing for oil will depend largely on future developments, which are highly uncertain and cannot be accurately predicted, including new information which may emerge concerning the severity of the outbreak and actions by government authorities to contain the outbreak or treat its impact. Furthermore, the impacts of a potential worsening of global economic conditions and the continued disruptions to and volatility in the financial markets remain unknown.
Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results. For additional information, see the “Trends and Outlook” section of MD&A included in the 2019 Annual Report in addition to the exhibits contained within this Form 8-K.
How We Evaluate Our Operations
We conduct and report our operations in the midstream energy industry through eight reportable segments:
| • |
the Utica Shale, which is served by Summit Utica; |
| • |
Ohio Gathering, which includes our ownership interest in OGC and OCC; |
| • |
the Williston Basin, which is served by Polar and Divide and Bison Midstream; |
| • |
the DJ Basin, which is served by Niobrara G&P; |
| • |
the Permian Basin, which is served by Summit Permian; |
| • |
the Piceance Basin, which is served by Grand River; |
| • |
the Barnett Shale, which is served by DFW Midstream; and |
| • |
the Marcellus Shale, which is served by Mountaineer Midstream. |
Additionally, until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream.
Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 4 to the unaudited condensed consolidated financial statements).
Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and determining the amounts of cash distributions to pay to our unitholders. These metrics include:
| • |
throughput volume; |
| • |
revenues; |
| • |
operation and maintenance expenses; and |
| • |
segment adjusted EBITDA. |
We review these metrics on a regular basis for consistency and trend analysis. There have been no changes in the composition or characteristics of these metrics during the three months ended March 31, 2020.
Additional Information. For additional information, see the “Results of Operations” section herein and the notes to the unaudited condensed consolidated financial statements. For additional information on how these metrics help us manage our business, see the “How We Evaluate Our Operations” section of MD&A included in the 2019 Annual Report in addition to the exhibits contained within this Form 8-K. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the unaudited condensed consolidated financial statements.
EX 99.5-6
Results of Operations
Consolidated Overview for the Three Months Ended March 31, 2020 and 2019
The following table presents certain consolidated and operating data.
| Three months ended March 31, | ||||||||
| 2020 | 2019 | |||||||
| (In thousands) | ||||||||
|
Revenues: |
||||||||
|
Gathering services and related fees |
$ | 83,792 | $ | 86,964 | ||||
|
Natural gas, NGLs and condensate sales |
13,780 | 37,928 | ||||||
|
Other revenues |
7,331 | 6,516 | ||||||
|
|
|
|
|
|||||
|
Total revenues |
104,903 | 131,408 | ||||||
|
|
|
|
|
|||||
|
Costs and expenses: |
||||||||
|
Cost of natural gas and NGLs |
8,225 | 31,759 | ||||||
|
Operation and maintenance |
21,811 | 24,222 | ||||||
|
General and administrative |
16,561 | 18,385 | ||||||
|
Depreciation and amortization |
29,666 | 27,764 | ||||||
|
Transaction costs |
11 | 2,337 | ||||||
|
Loss (gain) on asset sales, net |
115 | (961 | ) | |||||
|
Long-lived asset impairment |
3,821 | 44,951 | ||||||
|
|
|
|
|
|||||
|
Total costs and expenses |
80,210 | 148,457 | ||||||
|
|
|
|
|
|||||
|
Other (expense) income |
(427 | ) | 209 | |||||
|
Interest expense |
(23,828 | ) | (22,742 | ) | ||||
|
|
|
|
|
|||||
|
Income (loss) before income taxes and income (loss) loss from equity method investees |
438 | (39,582 | ) | |||||
|
Income tax benefit (expense) |
13 | (257 | ) | |||||
|
Income (loss) from equity method investees |
3,311 | (441 | ) | |||||
|
|
|
|
|
|||||
|
Net income (loss) |
$ | 3,762 | $ | (40,280 | ) | |||
|
|
|
|
|
|||||
|
Volume throughput (1): |
||||||||
|
Aggregate average daily throughput – natural gas (MMcf/d) |
1,281 | 1,462 | ||||||
|
Aggregate average daily throughput – liquids (Mbbl/d) |
98 | 103 | ||||||
| (1) |
Exclusive of volume throughput for Ohio Gathering. For additional information, see the “Ohio Gathering” section herein. |
Volumes – Gas. Natural gas throughput volumes decreased 181 MMcf/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:
| • |
a volume throughput decrease of 102 MMcf/d for the Piceance Basin segment. |
| • |
a volume throughput decrease of 64 MMcf/d for the Utica Shale segment. |
| • |
a volume throughput decrease of 27 MMcf/d for the Barnett Shale segment. |
| • |
a volume throughput decrease of 15 MMcf/d for the Marcellus Shale segment. |
| • |
a volume throughput increase of 18 MMcf/d for the Permian Basin segment. |
| • |
a volume throughput increase of 11 MMcf/d for the DJ Basin segment. |
Volumes – Liquids. Crude oil and produced water throughput volumes at the Williston segment decreased 5 Mbbl/d for the three months ended March 31, 2020 compared to the three months ended March 31, 2019.
For additional information on volumes, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” section herein.
EX 99.5-7
Revenues. Total revenues decreased $26.5 million during the three months ended March 31, 2020 compared to the prior year period primarily comprised of a $24.1 million decrease in natural gas, NGLs and condensate sales and a $3.2 million decrease in gathering services and related fees.
Gathering Services and Related Fees. Gathering services and related fees decreased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:
| • |
a $2.6 million decrease in gathering services and related fees in the Barnett Shale primarily reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019. Also impacting 2020 revenues was the presentation of $1.5 million of gathering services as a reduction to cost of natural gas and NGLs due to the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019. |
| • |
a $4.7 million decrease in gathering services and related fees in the Piceance Basin relating to lower volume throughput due to a lack of drilling and completion activity and natural production declines in addition to the sale of certain assets from our Red Rock Gathering system in December 2019. |
| • |
a $0.5 million decrease in gathering services and related fees in the Utica Shale as a result of natural production declines on existing wells partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers. |
| • |
a $1.9 million decrease in gathering services and related fees in the Williston Basin primarily reflecting a $1.5 million decrease in gathering services and related fees attributable to natural production declines and the sale of the Tioga Midstream system on March 22, 2019, whose 2019 financial results are included for the period from January 1, 2019 through March 22, 2019. |
| • |
a $3.1 million increase in gathering services and related fees in the DJ Basin relating to higher volume throughput due to increased drilling activity and a more favorable volume and gathering rate mix from customers, partially offset by natural production declines. |
| • |
a $1.9 million increase in gathering services and related fees in the Permian Basin due to higher volume growth from ongoing drilling and completion activity. |
Natural Gas, NGLs and Condensate Sales. Natural gas, NGLs and condensate sales decreased $24.1 million compared to the three months ended March 31, 2019, primarily reflecting lower natural gas, NGL and crude oil marketing services. The majority of the decrease in revenue is offset by a $23.5 million decrease in natural gas, NGL and condensate purchases.
Costs and Expenses. Total costs and expenses decreased $68.2 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily reflecting:
| • |
the impact of the March 2019 recognition of $34.9 million of certain long-lived asset impairments in the DJ Basin. |
| • |
a $23.5 million decrease in natural gas, NGLs and condensate purchases primarily driven by lower natural gas, NGL and crude oil marketing activity. |
| • |
the impact of the March 2019 recognition of $10.2 million of certain long-lived asset impairments in the Barnett Shale. |
| • |
the recognition in March 2020 of $3.6 million of certain long-lived asset impairments in the DJ Basin. |
| • |
a $2.4 million decrease in operation and maintenance expense primarily due to a $1.4 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes. |
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs decreased $23.5 million during the three months ended March 31, 2020 compared to the three months ended March 31, 2019, primarily driven by lower natural gas, NGL and crude oil marketing activity.
EX 99.5-8
Operation and Maintenance. Operation and maintenance expense decreased $2.4 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to a $1.3 million decrease in salaries and benefits costs and a $0.9 million decrease in property taxes.
General and Administrative. General and administrative expense decreased $1.8 million for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 primarily due to lower headcount associated with our cost cutting initiatives and lower performance-based compensation.
Depreciation and Amortization. The increase in depreciation and amortization expense during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was primarily due to the acceleration of depreciation on certain Williston Basin assets.
Transaction Costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with restructuring the equity structure of certain subsidiaries in 2019.
Interest Expense. The increase in interest expense for the three months ended March 31, 2020 compared to the three months ended March 31, 2019, was primarily due to a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.
For additional information, see the “Segment Overview for the Three Months Ended March 31, 2020 and 2019” and “Corporate and Other Overview for the Three Months Ended March 31, 2020 and 2019” sections herein.
Segment Overview for the Three Months Ended March 31, 2020 and 2019
Utica Shale. The Utica Shale reportable segment includes the Summit Utica system. Volume throughput for our Summit Utica system follows.
| Utica Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
222 | 286 | (22 | %) | ||||||||
Volume throughput declined compared to the three months ended March 31, 2019 as a result of natural production declines from existing wells partially offset by the completion of new wells throughout 2019 and in the first quarter of 2020, and a more favorable volume and gathering rate mix from customers.
Financial data for our Utica Shale reportable segment follows.
| Utica Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 6,962 | $ | 7,495 | (7 | %) | ||||||
|
|
|
|
|
|||||||||
|
Total revenues |
6,962 | 7,495 | (7 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Operation and maintenance |
941 | 1,216 | (23 | %) | ||||||||
|
General and administrative |
88 | 81 | 9 | % | ||||||||
|
Depreciation and amortization |
1,927 | 1,908 | 1 | % | ||||||||
|
Loss on asset sales, net |
16 | — | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
2,972 | 3,205 | (7 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
1,927 | 1,908 | ||||||||||
|
Adjustments related to capital reimbursement activity |
(5 | ) | (5 | ) | ||||||||
|
Loss on asset sales, net |
16 | — | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 5,928 | $ | 6,193 | (4 | %) | ||||||
|
|
|
|
|
|||||||||
EX 99.5-9
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA decreased $0.3 million compared to the three months ended March 31, 2019.
Ohio Gathering. The Ohio Gathering reportable segment includes OGC and OCC. We account for our investment in Ohio Gathering using the equity method. We recognize our proportionate share of earnings or loss in net income on a one-month lag based on the financial information available to us during the reporting period.
Gross volume throughput for Ohio Gathering, based on a one-month lag follows.
| Ohio Gathering | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
610 | 711 | (14 | %) | ||||||||
Volume throughput for the Ohio Gathering system in 2020 decreased compared to the year ended December 31, 2019 as a result of natural production declines on existing wells on the system partially offset by the completion of new wells throughout 2019.
Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.
| Ohio Gathering | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Proportional adjusted EBITDA for equity method investees |
$ | 7,939 | $ | 9,210 | (14 | %) | ||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 7,939 | $ | 9,210 | (14 | %) | ||||||
|
|
|
|
|
|||||||||
Segment adjusted EBITDA for equity method investees decreased $1.3 million compared to the three months ended March 31, 2019 primarily as a result of the lower volume throughput described above.
Williston Basin. The Polar and Divide, Bison Midstream and Tioga Midstream (through March 22, 2019; refer to Note 16 to the unaudited condensed consolidated financial statements for details on the sale of Tioga Midstream) systems provide our midstream services for the Williston Basin reportable segment. Volume throughput for our Williston Basin reportable segment follows.
| Williston Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Aggregate average daily throughput – natural gas (MMcf/d) |
14 | 16 | (13 | %) | ||||||||
|
Aggregate average daily throughput – liquids (Mbbl/d) |
98 | 103 | (5 | %) | ||||||||
Natural gas. Natural gas volume throughput decreased compared to the three months ended March 31, 2019, primarily reflecting natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells behind the Bison Midstream system in 2019 and 2020.
Liquids. The decrease in liquids volume throughput compared to the three months ended March 31, 2019, primarily reflected natural production declines and the sale of Tioga Midstream partially offset by the completion of new wells throughout 2019.
EX 99.5-10
Financial data for our Williston Basin reportable segment follows.
| Williston Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 23,797 | $ | 25,706 | (7 | %) | ||||||
|
Natural gas, NGLs and condensate sales |
4,324 | 5,585 | (23 | %) | ||||||||
|
Other revenues |
3,142 | 2,908 | 8 | % | ||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
31,263 | 34,199 | (9 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
1,663 | 2,709 | (39 | %) | ||||||||
|
Operation and maintenance |
6,722 | 6,516 | 3 | % | ||||||||
|
General and administrative |
538 | 341 | 58 | % | ||||||||
|
Depreciation and amortization |
6,495 | 5,436 | 19 | % | ||||||||
|
Loss (gain) on asset sales, net |
49 | (968 | ) | * | ||||||||
|
Long-lived asset impairment |
— | 10 | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
15,467 | 14,044 | 10 | % | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
6,495 | 5,436 | ||||||||||
|
Adjustments related to MVC shortfall payments |
(5,665 | ) | (5,549 | ) | ||||||||
|
Adjustments related to capital reimbursement activity |
(483 | ) | (350 | ) | ||||||||
|
Loss (gain) on asset sales, net |
49 | (968 | ) | |||||||||
|
Long-lived asset impairment |
— | 10 | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 16,192 | $ | 18,734 | (14 | %) | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.5 million compared to the three months ended March 31, 2019 primarily reflecting:
| • |
a decrease of $0.9 million of segment adjusted EBITDA contributed by the Tioga Midstream system compared to the three months ended March 31, 2019 due to the sale of Tioga Midstream on March 22, 2019. We also experienced lower natural gas volume throughput and lower liquids volume throughput on our systems. |
Other items to note:
| • |
On March 22, 2019, we sold the Tioga Midstream system and recorded a gain on sale of $0.9 million based on the difference between the consideration received and the then carrying value for Tioga Midstream at closing. The financial results of Tioga Midstream are included in our unaudited condensed consolidated financial statements for the period from January 1, 2019 through March 22, 2019. |
DJ Basin. The Niobrara G&P systems provide midstream services for the DJ Basin reportable segment. Volume throughput for our DJ Basin reportable segment follows.
| DJ Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
32 | 21 | 52 | % | ||||||||
Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area partially offset by natural production declines.
EX 99.5-11
Financial data for our DJ Basin reportable segment follows.
| DJ Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 6,855 | $ | 3,724 | 84 | % | ||||||
|
Natural gas, NGLs and condensate sales |
70 | 85 | (18 | %) | ||||||||
|
Other revenues |
1,034 | 1,007 | 3 | % | ||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
7,959 | 4,816 | 65 | % | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
9 | 10 | * | |||||||||
|
Operation and maintenance |
2,516 | 1,849 | 36 | % | ||||||||
|
General and administrative |
82 | 72 | 14 | % | ||||||||
|
Depreciation and amortization |
1,527 | 799 | 91 | % | ||||||||
|
Long-lived asset impairment |
3,635 | 34,721 | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
7,769 | 37,451 | (79 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
1,527 | 799 | ||||||||||
|
Adjustments related to capital reimbursement activity |
559 | (212 | ) | |||||||||
|
Long-lived asset impairment |
3,635 | 34,721 | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 5,911 | $ | 2,673 | 121 | % | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA increased $3.2 million compared to the three months ended March 31, 2019, primarily reflecting:
| • |
a $3.1 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity, a more favorable volume and gathering rate mix from customers, and the commissioning of our new natural gas processing plant in June 2019. This was partially offset by natural production declines. |
Other items to note:
| • |
During the quarter ended March 31, 2019, we impaired certain long-lived assets in the DJ Basin (see Note 5 to the unaudited condensed consolidated financial statements). The impairment had no impact on segment adjusted EBITDA for the three months ended March 31, 2020. |
Permian Basin. The Summit Permian system provides our midstream services for the Permian Basin reportable segment. Volume throughput for our Permian Basin reportable segment follows.
| Permian Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
33 | 15 | 120 | % | ||||||||
Volume throughput increased compared to the three months ended March 31, 2019, primarily as a result of ongoing drilling and completion activity across our service area.
Financial data for our Permian Basin reportable segment follows.
EX 99.5-12
| Permian Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (In thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 2,311 | $ | 366 | 531 | % | ||||||
|
Natural gas, NGLs and condensate sales |
4,512 | 4,221 | 7 | % | ||||||||
|
Other revenues |
187 | 32 | 484 | % | ||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
7,010 | 4,619 | 52 | % | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
4,149 | 4,245 | (2 | %) | ||||||||
|
Operation and maintenance |
1,187 | 891 | 33 | % | ||||||||
|
General and administrative |
93 | 33 | 182 | % | ||||||||
|
Depreciation and amortization |
1,345 | 1,072 | 25 | % | ||||||||
|
Loss on asset sales, net |
4 | — | * | |||||||||
|
Long-lived asset impairment |
182 | — | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
6,960 | 6,241 | 12 | % | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
1,345 | 1,072 | ||||||||||
|
Loss on asset sales, net |
4 | — | ||||||||||
|
Long-lived asset impairment |
182 | — | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 1,581 | $ | (550 | ) | * | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA increased $2.1 million compared to the three months ended March 31, 2019, primarily reflecting a $1.9 million increase in gathering services and related fees primarily as a result of volume growth from ongoing drilling and completion activity.
Piceance Basin. The Grand River system provides midstream services for the Piceance Basin reportable segment. Volume throughput for our Piceance Basin reportable segment follows.
| Piceance Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Aggregate average daily throughput (MMcf/d) |
383 | 485 | (21 | %) | ||||||||
Volume throughput decreased compared to the three months ended March 31, 2019, as a result of a natural production declines.
EX 99.5-13
Financial data for our Piceance Basin reportable segment follows.
| Piceance Basin | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 27,189 | $ | 31,840 | (15 | %) | ||||||
|
Natural gas, NGLs and condensate sales |
1,003 | 2,302 | (56 | %) | ||||||||
|
Other revenues |
1,065 | 1,138 | (6 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
29,257 | 35,280 | (17 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
457 | 1,473 | (69 | %) | ||||||||
|
Operation and maintenance |
4,938 | 7,299 | (32 | %) | ||||||||
|
General and administrative |
285 | 294 | (3 | %) | ||||||||
|
Depreciation and amortization |
11,298 | 11,791 | (4 | %) | ||||||||
|
Gain on asset sales, net |
(13 | ) | — | * | ||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
16,965 | 20,857 | (19 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
11,298 | 11,791 | ||||||||||
|
Adjustments related to MVC shortfall payments |
223 | (103 | ) | |||||||||
|
Adjustments related to capital reimbursement activity |
(243 | ) | (112 | ) | ||||||||
|
Gain on asset sales, net |
(13 | ) | — | |||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 23,557 | $ | 25,999 | (9 | %) | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.4 million compared to the three months ended March 31, 2019, primarily reflecting:
| • |
a $4.7 million decrease in gathering services and related fees as a result of natural production declines. |
| • |
a $2.4 million decrease in operation and maintenance expense primarily due to $1.2 million in lower compensation expense and a $0.4 million decrease in property taxes. |
Other items to note:
| • |
In December 2019, we sold certain assets from our Red Rock Gathering system for $12 million. The financial contribution of these assets are included in our unaudited condensed consolidated financial statements and footnotes for the period from January 1, 2019 through December 1, 2019. |
Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. Volume throughput for our Barnett Shale reportable segment follows.
| Barnett Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
233 | 260 | (10 | %) | ||||||||
Volume throughput decreased compared to the three months ended March 31, 2019 reflecting natural production declines partially offset by new volumes from well completion activity through the third quarter of 2019.
Financial data for our Barnett Shale reportable segment follows.
EX 99.5-14
| Barnett Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 10,443 | $ | 13,025 | (20 | %) | ||||||
|
Natural gas, NGLs and condensate sales |
3,871 | 604 | 541 | % | ||||||||
|
Other revenues (1) |
1,260 | 1,656 | (24 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Total revenues |
15,574 | 15,285 | 2 | % | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
1,947 | — | * | |||||||||
|
Operation and maintenance |
4,695 | 5,498 | (15 | %) | ||||||||
|
General and administrative |
378 | 228 | 66 | % | ||||||||
|
Depreciation and amortization |
3,797 | 3,941 | (4 | %) | ||||||||
|
Loss on asset sales, net |
59 | 7 | * | |||||||||
|
Long-lived asset impairment |
4 | 10,220 | * | |||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
10,880 | 19,894 | (45 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
4,032 | 4,330 | ||||||||||
|
Adjustments related to MVC shortfall payments |
— | 1,453 | ||||||||||
|
Adjustments related to capital reimbursement activity |
(29 | ) | (27 | ) | ||||||||
|
Loss on asset sales, net |
59 | 7 | ||||||||||
|
Long-lived asset impairment |
4 | 10,220 | ||||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 8,760 | $ | 11,374 | (23 | %) | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
| (1) |
Includes the amortization expense associated with our favorable gas gathering contracts as reported in other revenues. |
Three months ended March 31, 2020. Segment adjusted EBITDA decreased $2.6 million compared to the three months ended March 31, 2019 primarily reflecting:
| • |
a $1.5 million decrease in adjustments related to MVC shortfall payments attributable to an MVC that expired in 2019 and a $1.7 million decrease in total revenues less cost of natural gas and NGLs which primarily reflects lower volume throughput. |
Other items to note:
| • |
In March 2019, we impaired certain long-lived assets in the Barnett Shale (see Note 5 to the unaudited condensed consolidated financial statements). The noncash impairment expense had no impact on segment adjusted EBITDA for the three months ended March 31, 2019. |
| • |
Also impacting total revenues and cost of natural gas and NGLs for the three months ended March 31, 2020, was the presentation of certain gathering services as a reduction to cost of natural gas and NGLs and the assignment of certain marketing arrangements from Corporate and Other to our DFW Midstream operations that occurred in June 2019. |
Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment. Volume throughput for the Marcellus Shale reportable segment follows.
| Marcellus Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
|
Average daily throughput (MMcf/d) |
364 | 379 | (4 | %) | ||||||||
Volume throughput decreased compared to the three months ended March 31, 2019 primarily due to natural production declines partially offset by additional drilling and completion activities in the third quarter of 2019.
EX 99.5-15
Financial data for our Marcellus Shale reportable segment follows.
| Marcellus Shale | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Gathering services and related fees |
$ | 6,235 | $ | 6,197 | 1 | % | ||||||
|
|
|
|
|
|||||||||
|
Total revenues |
6,235 | 6,197 | 1 | % | ||||||||
|
|
|
|
|
|||||||||
|
Costs and expenses: |
||||||||||||
|
Operation and maintenance |
813 | 954 | (15 | %) | ||||||||
|
General and administrative |
93 | 92 | 1 | % | ||||||||
|
Depreciation and amortization |
2,300 | 2,283 | 1 | % | ||||||||
|
|
|
|
|
|||||||||
|
Total costs and expenses |
3,206 | 3,329 | (4 | %) | ||||||||
|
|
|
|
|
|||||||||
|
Add: |
||||||||||||
|
Depreciation and amortization |
2,300 | 2,283 | ||||||||||
|
Adjustments related to capital reimbursement activity |
(9 | ) | (9 | ) | ||||||||
|
|
|
|
|
|||||||||
|
Segment adjusted EBITDA |
$ | 5,320 | $ | 5,142 | 3 | % | ||||||
|
|
|
|
|
|||||||||
| * |
Not considered meaningful |
Three months ended March 31, 2020. Segment adjusted EBITDA increased $0.2 million compared to the three months ended March 31, 2019.
Corporate and Other Overview for the Three Months Ended March 31, 2020 and 2019
Corporate and Other represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, natural gas and crude oil marketing services, construction management fees related to the Double E Project, transaction costs and interest expense.
| Corporate and Other | ||||||||||||
| Three months ended March 31, | ||||||||||||
| 2020 | 2019 |
Percentage
Change |
||||||||||
| (Dollars in thousands) | ||||||||||||
|
Revenues: |
||||||||||||
|
Total revenues |
643 | 23,517 | (97 | %) | ||||||||
|
Costs and expenses: |
||||||||||||
|
Cost of natural gas and NGLs |
— | 23,322 | * | |||||||||
|
General and administrative |
15,004 | 17,244 | (13 | %) | ||||||||
|
Transaction costs |
11 | 2,337 | * | |||||||||
|
Interest expense |
23,828 | 22,742 | 5 | % | ||||||||
| * |
Not considered meaningful |
Total Revenues. Total revenues attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services (primarily natural gas sales). The decrease of $22.9 million compared to the three months ended March 31, 2019 was attributable to lower natural gas, NGL and crude oil marketing activity.
Cost of Natural Gas and NGLs. Cost of natural gas and NGLs attributable to Corporate and Other was due to natural gas, NGL and crude oil marketing services. The decrease of $23.3 million compared to the three months ended March 31, 2019 was attributable to lower marketing activity.
General and Administrative. General and administrative expense decreased $2.2 million compared to the three months ended March 31, 2019 primarily due to a decrease in salaries and benefits costs associated with lower headcount from our cost cutting initiatives.
EX 99.5-16
Transaction costs. The decrease in transaction costs recognized during the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to the financial advisory costs associated primarily with restructuring the equity structure of certain subsidiaries in 2019.
Interest Expense. Interest expense increased $2.7 million compared to the three months ended March 31, 2019 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility. The increase was partially offset by a lower outstanding balance on the Term Loan B.
Summarized Financial Information
On March 2, 2020, the SEC issued Final Rule Release No. 33-10762, Financial Disclosures about Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities (“Release 33-10762”), that amends the disclosure requirements related to certain registered securities that are guaranteed and those that are collateralized by the securities of an affiliate.
Under Release 33-10762, an SEC registrant may continue to omit separate financial statements of subsidiary issuers and guarantors when (1) the subsidiary issuer is consolidated with the parent company and its security is either (a) co-issued jointly and severally with the parent company’s security or (b) the subsidiary issuer’s security is fully and unconditionally guaranteed by the parent company and (2) the parent company provides supplemental financial and non-financial disclosure about the subsidiary issuers and/or guarantors and the guarantees.
The rules become effective January 4, 2021, with voluntary compliance permitted immediately. The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 9 to the unaudited condensed consolidated financial statements). SMLP has concluded that it is eligible to provide Alternative Disclosures under the amended disclosure requirements and has early adopted Release 33-10762 as of and for the three months ended March 31, 2020.
The supplemental summarized financial information below reflects SMLP’s separate accounts, the combined accounts of Summit Holdings and its 100% owned finance subsidiary, Finance Corp (the “Co-Issuers”) and the Guarantor Subsidiaries (the Co-Issuers and, together with the Guarantor Subsidiaries, the “Obligor Group”) for the dates and periods indicated. The financial information of the Obligor Group is presented on a combined basis and intercompany balances and transactions between the Co-Issuers and Guarantor Subsidiaries have been eliminated. There were no reportable transactions between the Co-Issuers and Obligor Group and the subsidiaries that were not issuers or guarantors of the Senior Notes.
Payments to holders of the Senior Notes are affected by the composition of and relationships among the Co-Issuers, the Guarantor Subsidiaries and Permian Holdco and Summit Permian Transmission, who are unrestricted subsidiaries of SMLP and are not issuers or guarantors of the Senior Notes. The assets of our unrestricted subsidiaries are not available to satisfy the demands of the holders of the Senior Notes. In addition, our unrestricted subsidiaries are subject to certain contractual restrictions related to the payment of dividends, and other rights in favor of their non-affiliated stakeholders, that limit their ability to satisfy the demands of the holders of the Senior Notes.
A list of each of SMLP’s subsidiaries that is a guarantor, issuer or co-issuer of our registered securities subject to the reporting requirements in Release 33-10762 is filed as Exhibit 22.1 to our Quarterly Report for the three months ended March 31, 2020 on Form 10-Q filed with the Securities and Exchange Commission on May 8, 2020.
Summarized Balance Sheet Information. Summarized balance sheet information as of March 31, 2020 and December 31, 2019 follow.
EX 99.5-17
| March 31, 2020 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Assets |
||||||||
|
Current assets |
$ | 10,732 | $ | 145,901 | ||||
|
Noncurrent assets |
12,133 | 2,361,034 | ||||||
|
Liabilities |
||||||||
|
Current liabilities |
$ | 15,604 | $ | 61,675 | ||||
|
Noncurrent liabilities |
163,163 | 1,539,410 | ||||||
| December 31, 2019 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Assets |
||||||||
|
Current assets |
$ | 7,396 | $ | 104,964 | ||||
|
Noncurrent assets |
9,835 | 2,389,032 | ||||||
|
Liabilities |
||||||||
|
Current liabilities |
$ | 14,527 | $ | 69,177 | ||||
|
Noncurrent liabilities |
163,163 | 1,514,250 | ||||||
Summarized Statements of Operations Information. For the purposes of the following summarized statements of operations, we allocate a portion of general and administrative expenses recognized at the SMLP parent to the Obligor Group to reflect what those entities’ results would have been had they operated on a stand-alone basis. Summarized statements of operations for the three months ended March 31, 2020 and for the year ended December 31, 2019 follow.
| Three months ended March 31, 2020 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Total revenues |
$ | — | $ | 104,903 | ||||
|
Total costs and expenses |
1,172 | 78,990 | ||||||
|
(Loss) income before income taxes and income from equity method investees |
(5,208 | ) | 5,695 | |||||
|
Income from equity method investees |
— | 3,762 | ||||||
|
Net (loss) income |
(5,196 | ) | 9,457 | |||||
| Year ended December 31, 2019 | ||||||||
| SMLP | Obligor Group | |||||||
| (In thousands) | ||||||||
|
Total revenues |
$ | — | $ | 443,528 | ||||
|
Total costs and expenses |
8,719 | 397,939 | ||||||
|
Loss before income taxes and loss from equity method investees |
(25,805 | ) | (28,840 | ) | ||||
|
Loss from equity method investees (1) |
— | (336,950 | ) | |||||
|
Net loss |
(27,036 | ) | (365,790 | ) | ||||
| (1) |
Amount includes a $329.7 million impairment of our equity method investment in Ohio Gathering and a $6.3 million impairment of long-lived assets in OCC. |
EX 99.5-18
Liquidity and Capital Resources
On May 3, 2020, we suspended distributions to holders of our common units and suspended payment of distributions to holders of our Series A Preferred Units commencing with respect to the quarter ending March 31, 2020 to enable us to retain an incremental approximately $76 million of cash in the business annually, which we plan to use to de-lever the balance sheet, enhance liquidity and increase financial flexibility. The unpaid distributions on the Series A Preferred Units will continue to accrue. We expect to fund future capital expenditures with cash and cash equivalents on hand, cash flows generated from our operations, borrowings under our Revolving Credit Facility, future issuances of debt, preferred equity and equity securities and proceeds from potential asset divestitures.
We are closely monitoring the impact of the outbreak of COVID-19 on all aspects of our business, including how it will impact our liquidity and capital resources. Considering the current commodity price backdrop and COVID-19 pandemic, we have collaborated extensively with our customer base over the past several weeks. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers and, on a limited scale, temporary production curtailments predominantly in the Williston Basin and DJ Basin reportable segments, we now expect 2020 total capital expenditures to range from $30 million to $50 million.
We are currently in compliance with all covenants contained in our Revolving Credit Facility, Term Loan B and Senior Notes, and at March 31, 2020, SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the Revolving Credit Agreement) were 5.05 to 1.0 and 2.26 to 1.0, respectively, relative to maximum threshold limits of 5.5x and 3.75x. Given further deterioration of market conditions, decreased drilling activity, the deferral of well completions from customers, limitations on access to capital markets to fund our capital expenditures and, on a limited scale, temporary production curtailments, we could have total leverage and senior secured leverage ratios that are higher than the levels prescribed in the applicable indebtedness agreements. Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows.
As we cannot predict the duration or scope of the COVID-19 pandemic and its impact on our customers and suppliers, the potential negative financial impact to our results cannot be reasonably estimated but could be material. We are actively managing the business to maintain cash flow and we have sufficient available liquidity. We believe that these factors will allow us to meet our anticipated funding requirements.
Capital Markets Activity
We had no capital markets activity during the three months ended March 31, 2020. For additional information, see the “Liquidity and Capital Resources – Capital Markets Activity” section of MD&A included in the 2019 Annual Report in addition to the exhibits contained within this Form 8-K.
Debt
Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility that matures in May 2022. As of March 31, 2020, the outstanding balance of the Revolving Credit Facility was $698.0 million and the unused portion totaled $542.9 million, after giving effect to the issuance thereunder of a $9.1 million outstanding but undrawn irrevocable standby letter of credit. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of March 31, 2020 was approximately $120 million. There were no defaults or events of default during the three months ended March 31, 2020, and, as of March 31, 2020, we were in compliance with the financial covenants in the Revolving Credit Facility. See Notes 9 and 15 to the unaudited condensed consolidated financial statements for more information on the Revolving Credit Facility and the issuance of the $9.1 million letter of credit, respectively.
Senior Notes. In February 2017, the Co-Issuers co-issued $500.0 million of 5.75% Senior Notes. In July 2014, the Co-Issuers co-issued $300.0 million of 5.50% Senior Notes. There were no defaults or events of default as of and for the three months ended March 31, 2020 on either series of senior notes.
Term Loan B. At March 31, 2020, the outstanding balance of the Term Loan B was $160.8 million and we were in compliance the Term Loan B’s financial covenants. There were no defaults or events of default during the three months ended March 31, 2020.
EX 99.5-19
For additional information on our long-term debt, see Note 9 to the unaudited condensed consolidated financial statements.
LIBOR Transition
LIBOR is the basic rate of interest widely used as a reference for setting the interest rates on loans globally. In 2017, the United Kingdom’s Financial Conduct Authority, which regulates LIBOR, announced that it intends to phase out LIBOR by the end of 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large U.S. financial institutions, is considering replacing U.S. dollar LIBOR with a new index, the Secured Overnight Financing Rate (“SOFR”), calculated using short-term repurchase agreements backed by Treasury securities. We are evaluating the potential impact of the eventual replacement of the LIBOR benchmark interest rate, however, we are not able to predict whether LIBOR will cease to be available after 2021, whether SOFR will become a widely accepted benchmark in place of LIBOR, or what the impact of such a possible transition to SOFR may be on our business, financial condition and results of operations.
We will need to renegotiate our Revolving Credit Facility to determine the interest rate to replace LIBOR with the new standard that is established. The potential effect of any such event on interest expense cannot yet be determined.
Cash Flows
The components of the net change in cash and cash equivalents were as follows:
| March 31, | ||||||||
| 2020 | 2019 | |||||||
| (In thousands) | ||||||||
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Net cash provided by operating activities |
$ | 70,201 | $ | 45,193 | ||||
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Net cash (used in) provided by investing activities |
(76,399 | ) | 28,493 | |||||
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Net cash provided by (used in) financing activities |
46,657 | (74,771 | ) | |||||
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Net change in cash, cash equivalents and restricted cash |
$ | 40,459 | $ | (1,085 | ) | |||
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Operating activities. Cash flows from operating activities for the three months ended March 31, 2020 primarily reflected:
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a $13.8 million increase in accounts receivable related to the timing of invoicing and cash collections; |
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a $3.7 million increase in accounts payable due to the timing of payment obligations; |
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a $2.8 million increase in deferred revenue for cash receipts not yet recognized as revenue; and |
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other changes in working capital. |
Investing activities. Cash flows used in investing activities during the three months ended March 31, 2020 primarily reflected:
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$58.0 million for investments in the Double E joint venture relating to the Double E Project; and |
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$18.6 million of capital expenditures primarily attributable to the DJ Basin of $6.3 million, the Williston Basin of $4.9 million and Summit Permian of $3.3 million. |
Cash flows used in investing activities during the three months ended March 31, 2019 primarily reflected:
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$89.5 million of net proceeds from the Tioga Midstream sale; and |
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$60.8 million of capital expenditures primarily attributable to the ongoing development of the DJ Basin of $28.4 million, Corporate and Other of $16.1 million (inclusive of capital expenditures of $15.8 million relating to the Double E Project), the Williston Basin of $8.0 million and Summit Permian of $7.1 million. |
Financing activities. Cash flows used in financing activities during the three months ended March 31, 2020 primarily reflected:
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$33.9 million of net proceeds from the issuance of Subsidiary Series A Preferred Units; |
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$21.0 million of net borrowings under our Revolving Credit Facility; and |
EX 99.5-20
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$6.0 million of distributions. |
Cash flows used in financing activities during the three months ended March 31, 2019 primarily reflected:
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$27.4 million of distributions; |
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$32.0 million of net repayments under our Revolving Credit Facility. |
Contractual Obligations Update
Double E Project
Upon completion of the Double E Project, we expect to own at least a 50% interest in the Double E Project, will lead the development, permitting and construction of the Double E Project and will operate the pipeline upon commissioning. At our current 70% interest, we estimate that our share of the capital expenditures required to develop the Double E Project will total approximately $350.0 million, and that more than 90% of those capital expenditures will be incurred in 2020 and 2021. Assuming timely receipt of the required regulatory approvals (including the Federal Energy Regulatory Commission’s issuance of the certificate required for us to pursue the Double E Project) and no material delays in construction, we expect that the Double E Project will be placed into service in the third quarter of 2021.
Capital Requirements
Our business is capital intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our Partnership Agreement requires that we categorize our capital expenditures as either:
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maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or |
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expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term. |
For the three months ended March 31, 2020, cash paid for capital expenditures totaled $18.6 million (see Note 4 to the unaudited condensed consolidated financial statements) which included $5.1 million of maintenance capital expenditures. For the three months ended March 31, 2020, there were no contributions to Ohio Gathering and we contributed $58.0 million to Double E (see Note 8 to the unaudited condensed consolidated financial statements).
We rely primarily on internally generated cash flow as well as external financing sources, including commercial bank borrowings and the issuance of debt, equity and preferred equity securities, and proceeds from potential asset divestitures to fund our capital expenditures. We believe that our Revolving Credit Facility, together with internally generated cash flow and access to debt or equity capital markets, will be adequate to finance our business for the foreseeable future without adversely impacting our liquidity.
Considering the current commodity price backdrop and COVID-19 pandemic, we will remain disciplined with respect to future capital expenditures, which will be primarily concentrated on the Double E Project and accretive expansions of our existing systems in our Core Focus Areas. We continue to advance our financing plans for our equity interest in Double E, which we intend to be credit neutral to Summit. We are currently targeting a financing structure that limits cash investments by us during 2020, and which shifts a substantial majority of our Double E capital commitments to third parties. On December 24, 2019, we entered into an agreement with TPG Energy Solutions Anthem, L.P. (“TPG”) to fund up to $80 million of Permian Holdco’s future capital calls associated with the Double E Project. Simultaneously, on December 24, 2019, we issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco to TPG for net proceeds of $27.3 million.
During the three months ended March 31, 2020, we issued an additional 35,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. We used the net proceeds of $34.4 million (after deducting underwriting discounts and offering expenses) to fund Summit’s share of capital expenses associated with the Double E Project.
EX 99.5-21
There are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreements with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other financing sources.
Credit and Counterparty Concentration Risks
We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees.
Certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customers’ wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customers’ commodities flow and, in many cases, the only way for our customers to get their production to market.
We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting its MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.
For additional information, see Notes 4, 9, 11 and 16 to the unaudited condensed consolidated financial statements.
Off-Balance Sheet Arrangements
We had no off-balance sheet arrangements as of or during the three months ended March 31, 2020.
Critical Accounting Estimates
We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. There have been no changes to our significant accounting policies since December 31, 2019.
Forward-Looking Statements
Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officers and employees during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, our subsidiaries, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.
EX 99.5-22
Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:
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fluctuations in natural gas, NGLs and crude oil prices, including as of a result of political or economic measures taken by various countries in response to the OPEC price war; |
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the extent and success of our customers’ drilling efforts, as well as the quantity of natural gas, crude oil and produced water volumes produced within proximity of our assets; |
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the current and potential future impact of the COVID-19 pandemic on our business, results of operations, financial position or cash flows; |
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failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects; |
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competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems; |
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actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers; |
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our ability to divest of certain of our assets to third parties on attractive terms, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets; |
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the ability to attract and retain key management personnel; |
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commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets; |
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changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets; |
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restrictions placed on us by the agreements governing our debt and preferred equity instruments; |
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the availability, terms and cost of downstream transportation and processing services; |
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natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control; |
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operational risks and hazards inherent in the gathering, compression, treating and/or processing of natural gas, crude oil and produced water; |
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weather conditions and terrain in certain areas in which we operate; |
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any other issues that can result in deficiencies in the design, installation or operation of our gathering, compression, treating and processing facilities; |
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timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule; |
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our ability to finance our obligations related to capital expenditures, including through opportunistic asset divestitures or joint ventures and the impact any such divestitures or joint ventures could have on our results; |
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the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements and federal, state and local restrictions or requirements applicable to oil and/or gas drilling, production or transportation; |
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the ability of SMP Holdings to meet its obligations under the SMPH Term Loan; |
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changes in tax status; |
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the effects of litigation; |
EX 99.5-23
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changes in general economic conditions; and |
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certain factors discussed elsewhere in this report. |
Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units, preferred units and senior notes.
The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.
EX 99.5-24