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Summit Midstream Partners, LP - Annual Report: 2019 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from        to        

Commission file number: 001-35666

Summit Midstream Partners, LP

(Exact name of registrant as specified in its charter)

Delaware

(State or other jurisdiction of

incorporation or organization)

 

45-5200503

(I.R.S. Employer

Identification No.)

910 Louisiana Street, Suite 4200

Houston, TX

(Address of principal executive offices)

 

77002

(Zip Code)

(832) 413-4770

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Securities Act:

 Title of each class

Trading Symbol(s)

Name of each exchange on which registered

Common Units

SMLP

New York Stock Exchange

 Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes          No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Act.     Yes          No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.     Yes          No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).     Yes          No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

 

Accelerated filer

 

 

 

 

 

Non-accelerated filer

 

Smaller reporting company

 

 

 

 

 

Emerging growth company

 

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes          No

The aggregate market value of the common units held by non-affiliates of the registrant as of June 28, 2019, was $309,575,112.

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:

Class

 

As of February 14, 2020

Common Units

 

93,613,194 units

DOCUMENTS INCORPORATED BY REFERENCE

None

 


Table of Contents

 

TABLE OF CONTENTS

 

Organizational Chart

3

Commonly Used or Defined Terms

4

 

 

 

PART I

 

8

Item 1.

Business.

8

Item 1A.

Risk Factors.

26

Item 1B.

Unresolved Staff Comments.

64

Item 2.

Properties.

65

Item 3.

Legal Proceedings.

66

Item 4.

Mine Safety Disclosures.

66

 

 

 

PART II

 

67

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

67

Item 6.

Selected Financial Data.

70

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations.

72

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk.

107

Item 8.

Financial Statements and Supplementary Data.

108

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

161

Item 9A.

Controls and Procedures.

161

Item 9B.

Other Information.

164

 

 

 

Part III

 

165

Item 10.

Directors, Executive Officers and Corporate Governance.

165

Item 11.

Executive Compensation.

171

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

190

Item 13.

Certain Relationships and Related Transactions, and Director Independence.

193

Item 14.

Principal Accounting Fees and Services.

195

 

 

 

Part IV

 

196

Item 15.

Exhibits, Financial Statement Schedules.

196

Item 16.

Form 10-K Summary.

200

 

 

 

Signature Page

201

 

 

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Table of Contents

 

ORGANIZATIONAL CHART

 

 

3


Table of Contents

 

COMMONLY USED OR DEFINED TERMS

 

2014 SRS

the Partnership's shelf registration statement initially filed with the SEC in July 2014

    and amended in February 2017 which registered an indeterminate amount of

    common units, debt securities and guarantees (superseded by the 2017 SRS)

2016 Drop Down

the Partnership's March 3, 2016 acquisition from SMP Holdings of substantially all

    of (i) the issued and outstanding membership interests in Summit Utica,

    Meadowlark Midstream and Tioga Midstream and (ii) SMP Holdings’ 40%

    ownership interest in Ohio Gathering

2016 SRS

the Partnership's shelf registration statement declared effective in November 2016

    which registered up to $1.5 billion of equity and debt securities in primary

    offerings and 36,701,230 common units beneficially owned by Summit

    Investments and affiliates of the Sponsor (superseded by the 2020 SRS)

2017 SRS

the Partnership's automatic shelf registration statement of well-known seasoned

    issuers filed with the SEC in July 2017 which registered an indeterminate

    amount of common units, preferred units, debt securities and guarantees and

    subsequently amended in November 2017

2020 SRS

the Partnership's shelf registration statement filed in November 2019 and declared

    effective in January 2020, which registered an indeterminate amount of common

    units, preferred units, warrants, rights, debt securities and guarantees in primary

    offerings and 51,234,693 common units beneficially owned by SMP Holdings

    and SMLP Holdings

5.5% Senior Notes

Summit Holdings' and Finance Corp.’s 5.5% senior unsecured notes due August

    2022

7.5% Senior Notes

Summit Holdings' and Finance Corp.’s 7.5% senior unsecured notes redeemed

    in March 2017

5.75% Senior Notes

Summit Holdings' and Finance Corp.’s 5.75% senior unsecured notes due April

    2025

AMI

area of mutual interest; AMIs require that any production from wells drilled by our

    customers within the AMI be shipped on and/or processed by our gathering

    systems

associated natural gas

a form of natural gas which is found with deposits of petroleum, either dissolved

    in the crude oil or as a free gas cap above the crude oil in the reservoir

ASU

Accounting Standards Update

Audit Committee

the audit committee of the Board of Directors

Bbl

one barrel; used for crude oil and produced water and equivalent to 42 U.S. gallons

Bcf

one billion cubic feet

Bcfe/d

the equivalent of one billion cubic feet per day; generally calculated when liquids are

    converted into natural gas; determined using a ratio of six thousand cubic feet of

    natural gas to one barrel of liquids

Bison Midstream

Bison Midstream, LLC

Board of Directors

the board of directors of our General Partner

CAA

Clean Air Act

CEA

Commodity Exchange Act

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

CFTC

Commodity Futures Trading Commission

Compensation

    Committee

the compensation committee of the Board of Directors

Compensation

    Consultant

BDO USA, L.L.P.

condensate

a natural gas liquid with a low vapor pressure, mainly composed of propane, butane,

    pentane and heavier hydrocarbon fractions

Conflicts Committee

the conflicts committee of the Board of Directors

CWA

Clean Water Act

Deferred Purchase Price

    Obligation

the deferred payment liability recognized in connection with the 2016 Drop Down, as

    subsequently amended; also referred to as DPPO

DFW Midstream

DFW Midstream Services LLC

DJ Basin

Denver-Julesburg Basin

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Dodd-Frank Act

Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010

DOT

U.S. Department of Transportation

Double E

Double E Pipeline, LLC

Double E Project

the development and construction of a long-haul natural gas pipeline with an

    initial throughput capacity of 1.35 billion cubic feet per day that will provide

    transportation service from multiple receipt points in the Delaware Basin

    to various delivery points in and around the Waha Hub in Texas

dry gas

natural gas primarily composed of methane where heavy hydrocarbons and water

    either do not exist or have been removed through processing or treating

Energy Capital Partners

Energy Capital Partners II, LLC and its parallel and co-investment funds; also known

    as the Sponsor

EPA

Environmental Protection Agency

Epping

Epping Transmission Company, LLC

EPU

earnings or loss per unit

Equity Restructuring

a series of transactions consummated on March 22, 2019, pursuant to which the

    Partnership cancelled its IDRs and converted its 2% economic GP interest

    to a non-economic GP interest in exchange for 8,750,000 SMLP common

    units, which were issued to SMP Holdings

Exchange Act

Securities Exchange Act of 1934, as amended

FASB

Financial Accounting Standards Board

FERC

Federal Energy Regulatory Commission

Finance Corp.

Summit Midstream Finance Corp.

FTC

Federal Trade Commission

GAAP

accounting principles generally accepted in the United States of America

General Partner

Summit Midstream GP, LLC

GHG

greenhouse gas(es)

GP

general partner

GP interest

2.0% general partner interest of GP in the Partnership prior to the Equity

    Restructuring and a non-economic general partner interest after the Equity

    Restructuring

Grand River

Grand River Gathering, LLC

Guarantor Subsidiaries

Bison Midstream and its subsidiaries, Grand River and its subsidiaries, DFW

    Midstream, Summit Marketing, Summit Permian, Permian Finance, OpCo,

    Summit Utica, Meadowlark Midstream, Summit Permian II and Mountaineer

    Midstream

hub

geographic location of a storage facility and multiple pipeline interconnections

ICA

Interstate Commerce Act

IDRs

incentive distribution rights

IPO

initial public offering

IRS

Internal Revenue Service

LIBOR

London Interbank Offered Rate

Mbbl

one thousand barrels

Mbbl/d

one thousand barrels per day

Mcf

one thousand cubic feet

MD&A

Management's Discussion and Analysis of Financial Condition and Results of

    Operations

Meadowlark Midstream

Meadowlark Midstream Company, LLC

MMBtu

one million British Thermal Units

MMcf

one million cubic feet

MMcf/d

one million cubic feet per day

Mountaineer Midstream

Mountaineer Midstream Company, LLC

MQD

minimum quarterly distribution

MVC

minimum volume commitment

NAAQS

national ambient air quality standard

NEPA

National Environmental Policy Act

NGA

Natural Gas Act

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NGLs

natural gas liquids; the combination of ethane, propane, normal butane,

    iso-butane and natural gasolines that when removed from unprocessed

    natural gas streams become liquid under various levels of higher

    pressure and lower temperature

NGPA

Natural Gas Policy Act of 1978

Niobrara G&P

Niobrara Gathering and Processing system

Non-Guarantor

    Subsidiaries

Permian Holdco and Summit Permian Transmission

NYSE

New York Stock Exchange

OCC

Ohio Condensate Company, L.L.C.

OGC

Ohio Gathering Company, L.L.C.

Ohio Gathering

Ohio Gathering Company, L.L.C. and Ohio Condensate Company, L.L.C.

OPA

Oil Pollution Control Act

OpCo

Summit Midstream OpCo, LP

PHMSA

Pipeline and Hazardous Materials Safety Administration

play

a proven geological formation that contains commercial amounts of hydrocarbons

Permian Finance

Summit Midstream Permian Finance, LLC

Permian Holdco

Summit Permian Transmission Holdco, LLC

Polar and Divide

the Polar and Divide system; collectively Polar Midstream and Epping

Polar Midstream

Polar Midstream, LLC

produced water

water from underground geologic formations that is a by-product of natural gas and

    crude oil production

PSD

Prevention of Significant Deterioration

RCRA

Resource Conservation and Recovery Act

Red Rock Gathering

Red Rock Gathering Company, LLC

Remaining Consideration

the consideration to be paid to SMP Holdings in 2022 in connection with the 2016

    Drop Down, the present value of which is reflected on our balance sheets as the

    Deferred Purchase Price Obligation

Revolving Credit Facility

the Third Amended and Restated Credit Agreement dated as of May 26, 2017, as

    amended by the First Amendment to Third Amended and Restated Credit

    Agreement dated as of September 22, 2017 and by the Second Amendment

    to Third Amended and Restated Credit Agreement dated as of June 26, 2019

    and further amended December 24, 2019

SEC

Securities and Exchange Commission

Securities Act

Securities Act of 1933, as amended

segment adjusted

    EBITDA

total revenues less total costs and expenses; plus (i) other income excluding interest

    income, (ii) our proportional adjusted EBITDA for equity method investees, (iii)

    depreciation and amortization, (iv) adjustments related to MVC shortfall

    payments, (v) adjustments related to capital reimbursement activity, (vi) unit-

    based and noncash compensation, (vii) the change in the Deferred Purchase

    Price Obligation, (viii) impairments and (ix) other noncash expenses

    or losses, less other noncash income or gains

Senior Notes

The 5.5% Senior Notes and the 5.75% Senior Notes, collectively

Series A Preferred Units

Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units

shortfall payment

the payment received from a counterparty when its volume throughput does not

    meet its MVC for the applicable period

SMLP

Summit Midstream Partners, LP

SMLP Holdings

SMLP Holdings, LLC

SMLP LTIP

SMLP Long-Term Incentive Plan

SMP Holdings

Summit Midstream Partners Holdings, LLC

SPCC

Spill Prevention Control and Countermeasure

Sponsor

Energy Capital Partners II, LLC and its parallel and co-investment funds; also known

    as Energy Capital Partners

Subsidiary Series A

    Preferred Units

Series A Fixed Rate Cumulative Redeemable Preferred Units issued by Permian

    Holdco

Summit Holdings

Summit Midstream Holdings, LLC

Summit Investments

Summit Midstream Partners, LLC

Summit Niobrara

Summit Midstream Niobrara, LLC

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Summit Marketing

Summit Midstream Marketing, LLC

Summit Permian

Summit Midstream Permian, LLC

Summit Permian II

Summit Midstream Permian II, LLC

Summit Permian

    Transmission

Summit Permian Transmission, LLC

Summit Utica

Summit Midstream Utica, LLC

Tcfe

the equivalent of one trillion cubic feet

the Company

Summit Midstream Partners, LLC and its subsidiaries

the Partnership

Summit Midstream Partners, LP and its subsidiaries

throughput volume

the volume of natural gas, crude oil or produced water gathered, transported or

    passing through a pipeline, plant or other facility during a particular period;

    also referred to as volume throughput

Tioga Midstream

Tioga Midstream, LLC

unconventional resource

    basin

a basin where natural gas or crude oil production is developed from unconventional

    sources that require hydraulic fracturing as part of the completion process, for

    instance, natural gas produced from shale formations and coalbeds; also

    referred to as an unconventional resource play

VOC

volatile organic compound(s)

wellhead

the equipment at the surface of a well, used to control the well's pressure; also, the

    point at which the hydrocarbons and water exit the ground

 

 

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PART I

Item 1. Business.

SMLP is a Delaware limited partnership formed in May 2012. References to "we" or "our" refer collectively to SMLP and its subsidiaries. For additional information, see Note 1 to the consolidated financial statements.

Item 1. Business is divided into the following sections:

 

Overview

 

Business Strategies

 

Our Midstream Assets

 

Regulation of the Natural Gas and Crude Oil Industries

 

Environmental Matters

 

Other Information

 

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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. Our systems gather natural gas from pad sites, wells and central receipt points connected to our systems. Gathered natural gas volumes are then compressed, dehydrated, treated and/or processed for delivery to downstream pipelines serving processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to downstream pipelines and third-party rail terminals in the case of crude oil and to third-party disposal wells in the case of produced water. We generally refer to all of the services our systems provide as gathering services.

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 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 decrease 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.

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; and

 

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.

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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.

The systems that we operate and/or have significant ownership interests in have a diverse group of customers and counterparties comprising affiliates and/or subsidiaries of some of the largest natural gas and crude oil producers in North America.

Key customers in our Core Focus Areas are as follows:

 

Utica Shale – XTO Energy Inc. ("XTO") and Ascent Resources - Utica, LLC ("Ascent") are the key customers for Summit Utica.

 

Ohio Gathering – Ascent and Gulfport Energy Corporation ("Gulfport") are the key customers for Ohio Gathering;

 

Williston Basin – Whiting Petroleum Corp. ("Whiting"), Zavanna, LLC (“Zavanna”) and Bruin Williston Holdings, LLC (“Bruin”) are the key customers for Polar and Divide. Oasis Petroleum, Inc. ("Oasis") and a large U.S. independent crude oil and natural gas company, are the key customers for Bison Midstream.

 

DJ Basin – HighPoint Resources Corporation ("HighPoint") and a large U.S. independent crude oil and natural gas company are the key customers for Niobrara G&P.

 

Permian Basin – XTO is the key customer for Summit Permian.

We believe that our gathering systems in the Core Focus Areas are positioned for long-term growth through further development by our customers and increased utilization of our gathering systems. We intend to continue expanding our operations and creating additional scale in our Core Focus Areas through the execution of new, and the expansion of existing, strategic partnerships with our existing and prospective customers.

Key customers in our Legacy Areas are as follows:

 

Piceance Basin – Caerus Oil & Gas LLC ("Caerus") and Terra Energy Partners LLC ("Terra") are the key customers for Grand River.

 

Barnett Shale – Total Gas & Power North America, Inc. ("Total") is the key customer for DFW Midstream.

 

Marcellus Shale – Antero Resources Corp. ("Antero") is the key customer for Mountaineer Midstream.

We believe that our customers in our Legacy Areas will pursue a slower pace of drilling and completion activity than customers in our Core Focus Areas. As a result, volume throughput in our Legacy Areas could decline or experience a lower rate of growth than our gathering systems in our Core Focus Areas. In general, our gathering systems in our Legacy Areas have a more mature base of connected wells, have larger and longer-lived MVCs and experience lower volume throughput decline rates as compared to our gathering systems in our Core Focus Areas. We will continue to evaluate divestitures or joint ventures of certain of our gathering systems included in our Core Focus Areas or our Legacy Areas, which could result in a reallocation of capital or other resources to repay outstanding debt and other liabilities or re-invest in our Core Focus Areas.

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Our financial results are primarily driven by volume throughput across our gathering systems and by expense management. During 2019, aggregate natural gas volume throughput averaged 1,397 MMcf/d and crude oil and produced water volume throughput averaged 105.3 Mbbl/d. 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.

In addition, the vast majority of our gathering and/or processing agreements in both our Core Focus Areas and our Legacy Areas include AMIs. Our AMIs cover approximately 3.2 million surface acres in the aggregate, which includes more than 0.8 million surface acres associated with Ohio Gathering. Certain of our gathering and processing agreements also include MVCs. To the extent the customer does not meet its MVC, it is contractually obligated to make an MVC shortfall payment to cover the shortfall of required volume throughput not shipped or processed, either on a monthly or annual basis. We have designed our MVC provisions to ensure that we will generate a minimum amount of revenue from each customer over the life of the associated gathering and/or processing agreement, whether by collecting gathering or processing fees on actual throughput or from cash payments to cover any MVC shortfall. As of December 31, 2019, we had remaining MVCs totaling 1.8 Tcfe. Our MVCs have a weighted-average remaining life of 5.6 years (assuming contracted minimum volume commitments for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023.

We use a variety of financial and operational metrics to analyze our performance, including among others, throughput volume, revenues, operation and maintenance expenses and segment adjusted EBITDA. We view each of these operational and/or GAAP metrics as important factors in evaluating our profitability and determining the amount of cash distributions we pay to our unitholders.

For additional information on our results of operations, see Item 6. Selected Financial Data and the "Results of Operations" section included in the Item 7. MD&A.

Our Sponsor and Summit Investments.  Energy Capital Partners, together with its affiliated funds, is a private equity firm with over $19.0 billion in capital commitments that is focused on investing in North America's energy infrastructure. Energy Capital Partners has significant energy and financial expertise to complement its investment in us, including investments in the power generation, midstream oil and gas, electric transmission, energy equipment and services, environmental infrastructure and other energy-related sectors.

Summit Investments, which was formed in 2009 by current and former members of our management team and our Sponsor, is the ultimate owner of our General Partner. We are managed and operated by the Board of Directors and executive officers of our General Partner, which is managed and operated by Summit Investments. As a result, due to its ownership interest in Summit Investments and its representation on Summit Investments' board of managers, Energy Capital Partners controls our General Partner and its activities, thereby controlling SMLP.

 

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Business Strategies

Our key business strategies are as follows:

 

Maintaining our focus on fee-based revenue with minimal direct commodity price exposure.  We intend to maintain our focus on providing midstream energy services under primarily long-term and fee-based contracts. We believe that our focus on fee-based revenues with minimal direct commodity price exposure is essential to maintaining stable cash flows.

 

Allocating capital to maximize unitholder value.  We will seek to maximize unitholder value by allocating our available capital and maintaining our commitment to risk-informed stable cash flows. This may include a re-allocation of capital into new areas, existing areas or to satisfy other obligations of the Partnership, including the Deferred Purchase Price Obligation. In some cases, production from our customers in our Core Focus Areas is expected to grow in excess of our existing throughput capacity over time, which will create opportunities for additional midstream infrastructure development. We will continue to evaluate opportunistic divestitures or joint ventures of certain or our assets as part of this strategy, which could include certain assets located in our Core Focus Areas or Legacy Areas. For example, in March 2019, we sold the Tioga Midstream gathering system which was included in the Williston Basin segment, to affiliates of Hess Infrastructure Partners LP for a combined purchase price of approximately $90 million (see Note 17 to the consolidated financial statements).

 

Maintaining strong producer relationships to maximize utilization of all of our midstream assets.  We have cultivated strong producer relationships by focusing on customer service, reliable project execution and by operating our assets safely and reliably over time. We believe that our strong producer relationships will create future opportunities to optimize the utilization of the gathering systems in our Legacy Areas and develop new midstream energy infrastructure in our Core Focus Areas.

 

Continuing to prioritize safe and reliable operations. We believe that providing safe, reliable and efficient operations is a key component of our business strategy. We place a strong emphasis on employee training, operational procedures and enterprise technology, and we intend to continue promoting a high standard with respect to the efficiency of our operations and the safety of all of our constituents.

Our Midstream Assets

Our midstream assets, including assets in which we have a significant ownership interest, currently operate in the following unconventional resource plays:

Core Focus Areas

 

the Utica Shale, which is served by Summit Utica;

 

Ohio Gathering, which operates in the Appalachian Basin and includes our ownership interests 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; and

 

the Permian Basin, which is served by Summit Permian.

Legacy Areas

 

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.

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We compete with other midstream companies, producers and intrastate and interstate pipelines. Competition for volumes is primarily based on reputation, commercial terms, service levels, access to end-use markets, geographic proximity of existing assets to a producer's acreage and available capacity. We may also face competition to gather production outside of our AMIs and attract producer volumes to our gathering systems. Additionally, we could face incremental competition to the extent we make acquisitions.

We earn revenue by providing gathering, compression, treating and/or processing services pursuant to primarily long-term and fee-based gathering and processing agreements with some of the largest and most active producers in North America. The fee-based nature of these agreements enhances the stability of our cash flows by limiting our direct commodity price exposure.

The significant features of our gathering and processing agreements and the gathering systems to which they relate are discussed in more detail below. For additional operating and financial performance information, on a consolidated basis and by reportable segment, see the "Results of Operations" section in Item 7. MD&A.

Areas of Mutual Interest.  The vast majority of our gathering and processing agreements contain AMIs, some of which extend through 2036. The AMIs generally require that any production by our customers within the AMIs will be shipped on and/or processed by our assets. In general, our customers have not leased acreage that cover our entire AMIs but, to the extent that they lease additional acreage within our AMIs in the future, any production from wells drilled by them within that AMI will be dedicated to our systems.

Under certain of our gathering agreements, we have agreed to construct pipeline laterals to connect our gathering systems to producer pad sites located within the AMI. However, in certain circumstances we may choose not to fund a pad connection opportunity presented by a customer or we may choose not to fund capital calls in Ohio Gathering if we believe that the investment would not meet our internal return expectations. Under this scenario, the customer may, in certain circumstances, construct the infrastructure itself and sell it to us at a price equal to their cost plus an applicable profit margin, or, in some cases, we may release the relevant acreage dedication from the AMI. For Ohio Gathering, our joint venture partner may elect to fund 100% of the capital calls, which could reduce our ownership interests in OGC and/or OCC. For example, in 2019, we chose not to fund capital calls at OGC and OCC, and as a result, our ownership interest in those ventures was reduced from 40% to 38.5% and 40% to 38.9%, respectively, as of December 31, 2019.

Minimum Volume Commitments.  Certain of our gathering and/or processing agreements contain MVCs, which, like AMIs, benefit the development and ongoing operation of a gathering system because they provide a contracted monthly or annual minimum revenue stream. As of December 31, 2019, we had remaining MVCs totaling 1.8 Tcfe. Our MVCs had a weighted-average remaining life of 5.6 years (assuming contracted minimum volume commitments for the remainder of the term) and average approximately 0.9 Bcfe/d through 2023. In addition, certain of our customers have an aggregate MVC, which is a total amount of volume throughput that the customer has agreed to ship and/or process on our systems (or an equivalent monetary amount) over the MVC term. In these cases, once a customer achieves its aggregate MVC, any remaining future MVCs will terminate and the customer will then simply pay the applicable gathering or processing rate multiplied by the actual throughput volumes shipped or processed, pursuant to the contract. As a result of this mechanism, in many cases, the weighted-average remaining period for which our MVCs apply is less than the weighted-average of the remaining contract life.

For additional information on our MVCs, see Notes 2 and 9 to the consolidated financial statements.

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Utica Shale

The following table provides operating information regarding our Utica Shale reportable segment as of December 31, 2019.

 

 

 

Aggregate throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

Remaining MVCs (Bcf)

 

Weighted-average remaining contract life (Years)

 

Weighted-average remaining MVC life (Years)

Utica Shale

 

 

720

 

 

n/a

 

n/a

 

9.5

 

n/a

The Summit Utica system is a natural gas gathering system located in Belmont and Monroe counties in southeastern Ohio and serves producers targeting the dry gas window of the Utica and Point Pleasant shale formations. The Summit Utica system gathers and delivers natural gas, primarily under long-term, fee-based gathering agreements, which include acreage dedications. XTO and Ascent are the key customers of Summit Utica.

We have connected a substantial number of our customers’ pad sites to our gathering system and we expect to benefit in the near-term from incremental volumes arising from drilling and completion activity that is occurring and will continue to occur on previously connected pad sites. Over time, we intend to expand our midstream service offering for the Summit Utica system to connect additional customer pad sites and install centralized compression facilities. Centralized compression services have been dedicated to us in our gathering agreements and will eventually constitute a new revenue stream from our customers; however, to date, this service has not been required given the relatively high downhole pressures exhibited by dry gas wells in the Utica Shale compared to other unconventional shale plays.

The Summit Utica system interconnects with the Ohio River System pipeline, which provides access to the Clarington Hub and Rover Pipeline.

The Summit Utica system currently provides natural gas midstream services for the Utica Shale reportable segment.

Ohio Gathering

Ohio Gathering comprises a natural gas gathering system and condensate stabilization facility located in the core of the Utica Shale in southeastern Ohio. The gathering system spans the condensate, liquids-rich and dry gas windows of the Utica Shale for multiple producers that are targeting production from the Utica and Point Pleasant shale formations across Belmont, Monroe, Guernsey, Harrison and Noble counties in southeastern Ohio and is operated by our partner, MPLX LP (“MPLX”). Substantially all gathering services on the Ohio Gathering system are provided pursuant to long-term, fee-based gathering agreements. Ascent and Gulfport are Ohio Gathering's key customers. AMIs for Ohio Gathering total approximately 825,000 surface acres in the aggregate.

Condensate and liquids-rich natural gas production is gathered, compressed, dehydrated and delivered to the Cadiz and Seneca processing complexes, which total approximately 1.3 Bcf/d of processing capacity and are owned by a joint venture between MPLX and The Energy and Minerals Group. Dry gas production is gathered, dehydrated, compressed, and delivered to third-party pipelines serving the northeast and midwest markets.

As of December 31, 2019, we owned a 38.5% ownership interest in Ohio Gathering. For additional information, see Note 8 to the consolidated financial statements.

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Williston Basin

The following table provides operating information regarding our Williston Basin reportable segment as of December 31, 2019.

 

 

Aggregate throughput capacity -

liquids (Mbbl/d)

 

 

Aggregate throughput capacity -

natural gas (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcfe/d) (1)

 

 

Remaining MVCs (Bcfe) (1)

 

 

Weighted-average remaining contract life (Years) (1)(2)

 

 

Weighted-average remaining MVC life (Years) (1)(2)

 

Williston Basin

 

 

255

 

 

 

34

 

 

 

73

 

 

 

107

 

 

 

3.0

 

 

 

2.5

 

 

(1) Contract terms related to MVCs are presented for liquids and natural gas on a combined basis.

(2) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

AMIs for the Williston Basin reportable segment total approximately 1.2 million surface acres in the aggregate.

Polar and Divide.  The Polar and Divide system, which is located primarily in Williams and Divide counties in northwestern North Dakota, owns, operates and is currently developing crude oil and produced water gathering systems and transmission pipelines serving multiple customers that are targeting crude oil production from the Bakken and Three Forks shale formations. The Polar and Divide system is underpinned by long-term, fee-based gathering agreements, which include acreage dedications. Whiting, Zavanna and Bruin are the key customers of the Polar and Divide system.

Crude oil that is gathered by the Polar and Divide system is delivered to interconnects with (i) the Dakota Access Pipeline, (ii) the COLT Hub rail facility, (iii) Enbridge Inc’s North Dakota Pipeline System and (iv) Global Partners LP's Basin Transload rail terminal. Produced water is delivered to third-party disposal facilities.

The Polar and Divide system currently provides crude oil and produced water midstream services for the Williston Basin reportable segment.

Bison Midstream.  The Bison Midstream system is located in Mountrail and Burke counties in northwestern North Dakota. Bison Midstream gathers, compresses and treats associated natural gas that exists in the crude oil stream produced from the Bakken and Three Forks shale formations. Our gathering agreements for the Bison Midstream system include long-term, fee-based or percent-of-proceeds contracts. Volume throughput on the Bison Midstream system is underpinned by acreage dedications and MVCs from its key customers. A large U.S. independent crude oil and natural gas company and Oasis are the key customers of Bison Midstream.

Natural gas gathered on the Bison Midstream system is delivered to Aux Sable Midstream LLC's (“Aux Sable”) Palermo Conditioning Plant in Palermo, North Dakota and then delivered to downstream pipelines serving Aux Sable’s 2.1 Bcf/d natural gas processing plant in Channahon, Illinois.

The Bison Midstream system currently provides associated natural gas midstream services for the Williston Basin reportable segment.

DJ Basin

The following table provides operating information regarding our DJ Basin reportable segment as of December 31, 2019.

 

 

 

Aggregate throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

 

Remaining MVCs (Bcf)

 

 

Weighted-average remaining contract life (Years) (1)

 

 

Weighted-average remaining MVC life (Years) (1)

 

DJ Basin

 

 

60

 

 

 

9

 

 

 

13

 

 

 

7.0

 

 

 

3.1

 

 

(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

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AMIs for the DJ Basin reportable segment total approximately 185,000 surface acres in the aggregate.

The Niobrara G&P system is located near Hereford, Colorado, in Weld County, the largest crude oil and natural gas producing county in the state. Gathering and processing services on the Niobrara G&P system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Niobrara and Codell shale formations. HighPoint and a large U.S. independent crude oil and natural gas company are the key customers of the Niobrara G&P system and have underpinned our volume throughput with acreage dedications and MVCs.

The Niobrara G&P system operates a low-pressure associated natural gas gathering system, and a cryogenic natural gas processing plant with processing capacity of 60 MMcf/d. The Niobrara G&P system also processes liquids-rich natural gas that is produced by a customer in Laramie County, Wyoming and is delivered to the inlet of our processing plant by a third-party gathering system.

Residue gas is delivered to the Colorado Interstate Gas and Trailblazer Pipeline and processed NGLs are delivered to the Overland Pass Pipeline.

The Niobrara G&P system currently provides midstream services for the DJ Basin reportable segment.

Permian Basin

The following table provides operating information regarding our Permian Basin reportable segment as of December 31, 2019.

 

 

 

Aggregate throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

Remaining MVCs (Bcf)

 

Weighted-average remaining contract life (Years)

 

Weighted-average remaining MVC life (Years)

Permian Basin (1)

 

 

60

 

 

n/a

 

n/a

 

8.4

 

n/a

 

(1) Contract terms related to MVCs are excluded for confidentiality purposes.

AMIs for the Permian Basin reportable segment total approximately 89,000 surface acres in the aggregate.

The Summit Permian system is an associated natural gas gathering and processing system operating in the northern Delaware Basin in Eddy and Lea counties in New Mexico. Gathering and processing services on the Summit Permian system are provided pursuant to long-term, fee-based gathering agreements with producers that are primarily targeting crude oil production from the Bone Spring and Wolfcamp shale formations. XTO is the key customer of the Summit Permian system.

The Summit Permian system operates a low-pressure natural gas gathering system and a 60 MMcf/d cryogenic processing plant.

Residue natural gas is delivered to the Transwestern Pipeline and processed NGLs are delivered to the Lone Star NGL Pipeline.

Piceance Basin

The following table provides operating information regarding our Piceance Basin reportable segment as of December 31, 2019.

 

 

Aggregate throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

 

Remaining MVCs (Bcf)

 

 

Weighted-average remaining contract life (Years) (1)

 

 

Weighted-average remaining MVC life (Years) (1)

 

Piceance Basin

 

 

1,151

 

 

 

434

 

 

 

837

 

 

 

9.9

 

 

 

5.7

 

 

(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

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AMIs for the Piceance Basin reportable segment total approximately 654,000 surface acres in the aggregate.

Grand River is primarily located in Garfield County, one of the largest natural gas producing counties in Colorado. The Grand River system provides gathering services pursuant to primarily long-term and fee-based agreements with multiple producers, including its key customers, Caerus and Terra. Volume throughput on the Grand River system is underpinned with acreage dedications and MVCs.

The Grand River system is primarily a low-pressure gathering system that gathers natural gas produced from directional wells targeting the liquids-rich Mesaverde formation.

Natural gas gathered and/or processed on the Grand River system is compressed, dehydrated, processed and/or discharged to downstream pipelines serving (i) the Meeker Processing Complex, (ii) the Northwest Pipeline system and (iii) the TransColorado Pipeline system. Processed NGLs from Grand River are injected into the Mid-America Pipeline system or delivered to local markets. In addition, certain of our gathering agreements with our customers on the Grand River system permit us to retain condensate volumes that naturally discharge from the liquids-rich natural gas as it moves across our system.

The Grand River system currently provides midstream services for the Piceance Basin reportable segment.

Barnett Shale

The following table provides operating information regarding our Barnett Shale reportable segment as of December 31, 2019.

 

 

 

Throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

Remaining MVCs (Bcf)

 

Weighted-average remaining contract life (Years) (1)

 

Weighted-average remaining MVC life (Years) (1)

Barnett Shale

 

 

450

 

 

n/a

 

n/a

 

6.3

 

n/a

 

(1) Weighted average based on total remaining MVC (total remaining MVCs multiplied by average rate).

AMIs for the Barnett Shale reportable segment total approximately 124,000 surface acres.

The DFW Midstream system is primarily located in southeastern Tarrant County, in north-central Texas. We consider this area to be the core of the core of the Barnett Shale because of the quality of the geology and the high production profile of the wells drilled to date. The DFW Midstream system is underpinned by a long-term, fee-based gathering agreement with Total and additional customers.

The DFW Midstream system includes natural gas gathering pipelines located under both private and public property and is partially located along existing electric transmission corridors. Compression on the system is powered by electricity. To offset the costs we incur to operate the system's electric-drive compressors, we either retain a fixed percentage of the natural gas that we gather or pass through a portion of the power expense to our customers.

The DFW Midstream system currently has six primary interconnections with third-party, primarily intrastate pipelines. These interconnections enable us to connect our customers, directly or indirectly, with the major natural gas market hubs in Texas and Louisiana.

The DFW Midstream system currently provides midstream services for the Barnett Shale reportable segment.

Marcellus Shale

The following table provides operating information regarding our Marcellus Shale reportable segment as of December 31, 2019.

 

 

Throughput capacity (MMcf/d)

 

 

Average daily MVCs through 2023 (MMcf/d)

 

Remaining MVCs (Bcf)

 

Weighted-average remaining contract life (Years)

 

Weighted-average remaining MVC life (Years)

Marcellus Shale (1)

 

 

1,050

 

 

n/a

 

n/a

 

n/a

 

n/a

 

(1) Contract terms related to MVCs are excluded for confidentiality purposes.

The Mountaineer Midstream system is located in Doddridge and Harrison counties in West Virginia where it gathers natural gas under a long-term, fee-based contract with Antero, which is targeting liquids-rich natural gas production from the Marcellus Shale formation. Volume throughput on the Mountaineer Midstream system is underpinned by MVCs from Antero.

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The Mountaineer Midstream system, which is underpinned by a minimum revenue commitment from Antero, consists of a high-pressure natural gas gathering system and two compressor stations. This system gathers high-pressure natural gas received from upstream pipeline interconnections with Antero Midstream Corporation and Crestwood Equity Partners LP. Mountaineer Midstream serves as a critical inlet to the Sherwood Processing Complex, a primary destination for liquids-rich natural gas in northern West Virginia and one of the largest natural gas processing facilities in the United States.

The Mountaineer Midstream system currently provides midstream services for the Marcellus Shale reportable segment.

For additional information relating to our business and gathering systems, see the "Trends and Outlook" and "Results of Operations" sections in Item 7. MD&A.

 

Regulation of the Natural Gas and Crude Oil Industries

General.  Sales by producers of natural gas, crude oil, condensate and NGLs are currently made at market prices. However, gathering and transportation services are subject to various types of regulation, which may affect certain aspects of our business and the market for our services. FERC regulates the transportation of natural gas in interstate commerce and the interstate transportation of crude oil, petroleum products and NGLs. FERC regulation includes reviewing and accepting or approving rates and other terms and conditions for such transportation services, and authorizing and regulating the construction and operation of interstate natural gas pipelines. FERC is also authorized to prevent and sanction market manipulation in natural gas markets while the FTC is authorized to prevent and sanction market manipulation in petroleum markets and the CFTC is authorized to prevent and sanction fraud and price manipulations in the commodity and futures markets, including the energy futures markets. State and municipal regulations may apply to the production and gathering of certain natural gas, the construction and operation of natural gas and crude oil facilities and the rates and practices of gathering systems and intrastate pipelines.

Regulation of Crude Oil and Natural Gas Exploration, Production and Sales.  Sales of crude oil and NGLs are not currently regulated and are transacted at market prices. In 1989, the U.S. Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. FERC, which has the authority under the NGA to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of gas in interstate commerce), however, could re-impose price controls in the future.

Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations and conservation of resources. While these regulations do not directly apply to our business, they may affect our customers' ability to produce natural gas.

Regulation of the Gathering and Transportation of Natural Gas and Crude Oil.  We believe that the majority of our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC. Our Epping Pipeline interstate crude oil pipeline in North Dakota, which is owned and operated by Epping, is subject to FERC’s jurisdiction and oversight pursuant to FERC's authority under the ICA, and Epping has on file with FERC a tariff for interstate movements of crude oil on the pipeline. Additionally, our Double E Project, which is currently under consideration by FERC in Docket No. CP19-495-000 under Section 7(c) of the NGA for a certificate of public convenience and necessity, and is anticipated to provide interstate natural gas transmission service from the Delaware Basin in southeastern New Mexico to the Waha Hub in Texas, will be subject to FERC jurisdiction if approved. In 2018, FERC solicited public comment on its current policy on the certification of construction of new pipeline facilities, although it has not made any determinations yet on whether to make any changes to that policy. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements.

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Under FERC’s ICA jurisdiction, rates for interstate movements of liquids by pipeline are currently regulated primarily through an annual indexing methodology, under which pipelines increase or decrease their existing rates in accordance with a FERC-specified adjustment that sets a rate ceiling. This adjustment, which may be positive or negative in a given year, is subject to review every five years. For the five-year period beginning on July 1, 2016, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23%. In 2016, FERC proposed a policy change that would deny proposed index increases for pipelines under certain circumstances where revenues exceed cost-of-service by a certain percentage or where the proposed index increases exceed certain annual cost changes reported to FERC. FERC terminated this rulemaking on February 20, 2020 without adopting any part of the proposal. FERC will commence its five-year review of its index adjustment in 2020 with the new adjustment to become effective starting July 1, 2021.

Under current FERC regulations, liquids pipelines can request a rate increase that exceeds the rate obtained through the indexing methodology by using a cost-of-service approach, but a pipeline must establish that a substantial divergence exists between its actual costs and the rates resulting from the indexing methodology. The rates charged by Epping may also be affected by FERC’s March 15, 2018 announcement of a revised policy eliminating the recovery of an income tax allowance in cost-of-service-based rates by FERC-jurisdictional crude oil and natural gas pipelines owned by master limited partnerships. FERC has not required oil pipelines on an industry-wide basis to decrease their rates to implement the new policy, but FERC has stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by oil pipelines. The effect of the elimination of the income tax allowance for MLP pipelines, as well as the reduction in the corporate income tax rate resulting from the Tax Cuts and Jobs Act of 2017, will be taken into account in FERC’s next five-year review of index rate adjustments in 2020.

The ICA permits interested persons to challenge proposed new or changed rates and authorizes FERC to suspend the effectiveness of such rates for up to seven months and investigate such rates. If, upon completion of an investigation, FERC finds that the new or changed rate is unlawful, it is authorized to require the pipeline to refund revenues collected in excess of the just and reasonable rate during the term of the investigation. FERC may also investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates prospectively. Under certain circumstances, FERC could limit Epping’s ability to set rates based on costs or could order reduced rates and reparations to complaining shippers for up to two years prior to the date of a complaint. FERC also has the authority to change terms and conditions of service if it determines that they are unjust and unreasonable or unduly discriminatory or preferential. The ICA also imposes potential criminal liability for certain violations of the statute.

Intrastate pipelines, which may include some pipelines that perform gathering functions, may be subject to safety regulation by the DOT, although typically state regulatory authorities (operating under a federal certification) perform this function. State regulatory authorities also have jurisdiction over the rates and practices of intrastate pipelines and gathering systems, including requirements for ratable takes or non-discriminatory access to pipeline services. The basis for state regulation and the degree of regulatory oversight of gathering systems and intrastate pipelines varies from state to state. In Texas, we are regulated as a gas utility and have filed tariffs with the Railroad Commission of Texas to establish rates and terms of service for our DFW Midstream system assets. We have not been required to file tariffs in the other states in which we operate, although we are required to submit shape files and other information regarding the location and construction of underground gathering pipelines in North Dakota. The states in which we operate have adopted complaint-based regulation that allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve access issues and rate grievances, among other matters. State authorities in the states in which we operate generally have not initiated investigations of the rates or practices of gathering systems or intrastate pipelines in the absence of a complaint. State regulation of intrastate pipelines continues to evolve and may become more stringent in the future. For example, the North Dakota Industrial Commission recently adopted rule changes that resulted in additional construction and monitoring requirements for all pipelines, including, but not limited to, those that transport produced water, and has recently adopted reclamation bonding requirements for certain underground gathering pipelines in North Dakota.

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Natural gas, crude oil and produced water production, gathering and transportation, including the construction of new gathering facilities and expansion of existing gathering facilities may also be subject to local regulation, such as approval and permit requirements.

Anti-Market Manipulation Rules.  We are subject to the anti-market manipulation provisions in the NGA and the NGPA, as amended by the Energy Policy Act of 2005, which authorize FERC to impose fines of up to $1,291,894 per day per violation of the NGA, the NGPA, or their implementing regulations, subject to future adjustments for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,231,690 per violation, subject to future adjustment for inflation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The CFTC is directed under the CEA to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,212,866 per day per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the CEA. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

Safety and Maintenance.  We are subject to regulation by the DOT, which establishes federal safety standards for the design, construction, operation and maintenance of natural gas and crude oil pipeline facilities. In the Pipeline Safety Act of 1992, Congress expanded the DOT's regulatory authority to include regulated gathering lines that had previously been exempt from federal jurisdiction. The Pipeline Safety Improvement Act of 2002 and the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 established mandatory inspections for certain U.S. oil and natural gas transmission pipelines in high consequence areas. The Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 (“2011 Act”) reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines. In 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act reauthorized pipeline safety programs through 2019 and provided limited new authority, including the ability to issue emergency orders, while increasing transparency into the status of remaining actions required by the 2011 Act. As of the end of 2019, the PHMSA had not yet been reauthorized for funding through 2023, but the PHMSA indicates that its pipeline safety functions can continue to function, subject to restrictions in an appropriations act.

The DOT has delegated the implementation of pipeline safety requirements to PHMSA, which has adopted and enforces safety standards and procedures applicable to a limited number of our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing PHMSA regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high-population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from the integrity management requirements of PHMSA, we also operate a limited number of pipelines that are subject to the integrity management requirements. Those regulations require operators, including us, to:

 

perform ongoing assessments of pipeline integrity;

 

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

maintain processes for data collection, integration and analysis;

 

repair and remediate pipelines as necessary;

 

adopt and maintain procedures, standards and training programs for control room operations; and

 

implement preventive and mitigating actions.

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In October 2019, the PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.

Gathering systems like ours are also subject to a number of federal and state laws and regulations, including the Federal Occupational Safety and Health Act and comparable state statutes, the purposes of which are to protect the health and safety of workers, both generally and within the pipeline industry. In addition, the Occupational Safety and Health Administration hazard communication standard, EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that such information be provided to employees, state and local government authorities and the public.

Environmental Matters

General.  Our operation of pipelines and other assets for the gathering, treating and/or processing of natural gas and the gathering of crude oil and produced water is subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. As an owner or operator of these assets, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 

requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

 

limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

 

delaying system modification or upgrades during permit reviews;

 

requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

 

enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.

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The trend in environmental regulation is to place more stringent requirements, resulting in more restrictions and limitations, on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We also actively participate in industry groups that help formulate recommendations for addressing existing and future regulations.

The following is a discussion of the material environmental laws and regulations that relate to our business.

Hazardous Substances and Waste.  Our operations are subject to environmental laws and regulations relating to the management and release of solid and hazardous wastes and other substances, including hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste and may impose strict joint and several liability for the investigation and remediation of affected areas where hazardous substances may have been released or disposed. Furthermore, the Toxic Substances Control Act and analogous state laws, impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities. CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. We may handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

We also generate industrial wastes that are subject to the requirements of the RCRA and comparable state statutes. While the RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Although we generate minimal hazardous waste, it is possible that non-hazardous wastes, which could include wastes currently generated during our operations, will in the future be designated as hazardous wastes and, therefore, be subject to more rigorous and costly disposal requirements. Moreover, from time to time, the EPA and state regulatory agencies have considered the adoption of stricter disposal standards for non-hazardous wastes, including natural gas wastes.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although we believe that the previous operators utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal, without our knowledge. These properties and the wastes disposed thereon may be subject to CERCLA, the RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Air Emissions.  Our operations are subject to the federal CAA and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our facilities, and also impose various monitoring, control and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future to obtain and maintain operating permits and approvals for air pollutant emitting sources.

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In October 2015, the EPA issued a new lower NAAQS for ozone. The previous ozone standard was set at 75 parts per billion ("ppb"). The revised standard has been lowered to 70 ppb. The lowered ozone NAAQS could result in a significant expansion of ozone nonattainment areas across the United States, including areas in which we operate, which could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs. Impacts from the new standard have not yet been determined, as states are still in the process of incorporating the new standard into their respective state implementation plans. We will continue to monitor developments to determine if any adverse effects on our operations can be expected.

On June 3, 2016, the EPA finalized revisions to its 2012 New Source Performance Standard ("NSPS") OOOO for the oil and gas industry, to reduce emissions of greenhouse gases - most notably methane - along with smog-forming VOCs. The revisions, which are published in the Federal Register under Subpart OOOOa, included the addition of methane to the pollutants covered by the rule, along with requirements for detecting and repairing leaks at gathering and boosting stations. The revised rule applies to sources that have been modified, constructed, or reconstructed after September 18, 2015. In September 2019, the EPA published a rule proposing to reconsider certain aspects of both the 2012 and 2016 rules. This proposed rule would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The 2012 and 2016 rules remain in effect pending reconsideration. While we do not expect this rule to significantly impact our existing operations, future modifications or new construction may be adversely affected by the revised rule.

On November 16, 2016 the Bureau of Land Management ("BLM") issued a final rule to reduce venting and flaring of natural gas on public and Indian lands. The final rule mirrors many of the requirements found in NSPS OOOOa, with additional natural gas royalty requirements for flared volumes at sites already connected to gas capture infrastructure. In September 2018, the BLM published a final rule that rescinded several requirements of this rule. The September 2018 rule was challenged in the U.S. District Court for the Northern District of California almost immediately after issuance. The challenge is still pending. While the rule is expected to have little or no direct impact on our operations, our customers that are primarily upstream wellhead operators may be impacted by the requirements in this rule.

Water Discharges.  The CWA and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into regulated waters, which impacts our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits require us to control storm water runoff from some of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Except as otherwise disclosed in this annual report, we believe that we are in substantial compliance with all applicable requirements of the CWA and analogous state laws and regulations relating to water discharges.

Oil Pollution Act.  The OPA requires the preparation of an SPCC plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility's operations comply with the requirements. To be in compliance, the facility's SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security and training. Certain of our facilities are classified as SPCC-regulated facilities. We believe that they are in substantial compliance with all applicable requirements of OPA.

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Hydraulic Fracturing. Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations and is primarily presently regulated by state agencies. However, Congress has in the past and may in the future consider legislation to regulate hydraulic fracturing by federal agencies or limit the ability of companies to engage in hydraulic fracturing. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have recently been circulated by interested groups for potential consideration in upcoming elections, although none have yet obtained the requisite number of signatures. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state and reduced the oil and gas representation on the Colorado Oil and Gas Conservation Commission, which regulates the oil and gas industry in Colorado. Similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

The EPA has also moved forward with various regulatory actions, including approving new regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements that went into effect in 2015. Revisions to the green completion regulations were finalized in June 2016 and include additional requirements to reduce methane and VOCs. The EPA announced in April 2017 that it would review these regulations and in September 2019, the EPA published a rule proposing to reconsider certain aspects of the regulations. However, the regulations currently remain in effect. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The rescission rule is currently subject to a legal challenge. Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.

If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.

Endangered Species Act.  The Endangered Species Act restricts activities that may affect endangered or threatened species or their habitats. Some of our pipelines may be located in areas that are designated as habitats for endangered or threatened species.

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National Environmental Policy Act.  The NEPA establishes a national environmental policy and goals for the protection, maintenance and enhancement of the environment and provides a process for implementing these goals within federal agencies. Major projects having the potential to significantly impact the environment require review under NEPA. Many of our activities are covered under categorical exclusions which results in an expedited NEPA review process. Large upstream and downstream projects with significant cumulative impacts may be subject to longer NEPA review processes, which could impact the timing of those projects and our services associated with them.

Climate Change.  The EPA has adopted regulations under the CAA that, among other things, establish GHG emission limits from motor vehicles as well as establish PSD construction and Title V operating permit reviews for certain large stationary sources that are potential major sources of GHG emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that will be established by the states or, in some cases, by the EPA on a case-by-case basis.

EPA rules also require the reporting of GHG emissions from specified large GHG-emitting sources in the United States, including onshore and offshore oil and natural gas systems. We are required to report under these rules for our assets that have GHG emissions above the reporting thresholds. In October 2015, the EPA issued revisions to Subpart W of the GHG reporting rule to include reporting requirements for gathering and booster stations, onshore natural gas transmission pipelines, and completions and workovers of oil wells with hydraulic fracturing. This development resulted in increased monitoring and reporting for our operations and for upstream producers for whom we provide midstream services.

In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation.

Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016, after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intends to withdraw from the agreement. The earliest possible effective withdrawal date from the agreement is November 2020. However, there are no guarantees that the agreement will not be re-implemented in the United States, or re-implemented in part by certain state or local governments.

Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by making our products more or less desirable than competing sources of energy. To the extent that our products are competing with higher GHG-emitting energy sources, our products would become more desirable in the market with more stringent limitations on GHG emissions. Conversely, to the extent that our products are competing with lower GHG-emitting energy sources such as solar and wind, our products would become less desirable in the market with more stringent limitations on GHG emissions.

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Other Information

Employees.  SMLP does not have any employees. All of the employees required to conduct and support its operations are employed by Summit Investments, but these individuals are sometimes referred to as our employees. The officers of our General Partner manage our operations and activities. As of December 31, 2019, Summit Investments employed 261 people who provide direct, full-time support to our operations. None of our employees are covered by collective bargaining agreements, and we have never experienced any business interruption as a result of any labor disputes.

Availability of Reports.  We make certain filings with the SEC, including, among other filings, our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments and exhibits to those reports, available free of charge through our website, www.summitmidstream.com, as soon as reasonably practicable after the date they are filed with, or furnished to, the SEC. The SEC maintains an Internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC through the SEC’s website, http://www.sec.gov. Our press releases and recent investor presentations are also available on our website.

Item 1A. Risk Factors.

Item 1A. Risk Factors is divided into the following sections:

Risks Related to our Business

Risks Inherent in an Investment in Us

Tax Risks

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements of expenses incurred on our behalf by our General Partner, to enable us to sustain the distributions to holders of our common units.

We may not have sufficient available cash from operating surplus each quarter to sustain the distributions to holders of our common units. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

the volumes we gather, treat and process;

 

the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;

 

damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;

 

leaks or accidental releases of hazardous materials into the environment;

 

weather conditions and seasonal trends;

 

changes in the fees we charge for our services;

 

changes in contractual MVCs and our customer’s capacity to make MVC shortfall payments when due;

 

the level of competition from other midstream energy companies in our areas of operation;

 

changes in the level of our operating, maintenance and general and administrative expenses;

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regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and

 

prevailing economic and market conditions.

In addition, the actual amount of cash we will have available for distribution to our common unitholders will depend on other factors, some of which are beyond our control, including:

 

the level and timing of capital expenditures we make;

 

the level of our operating, maintenance and general and administrative expenses, including reimbursements of expenses incurred on our behalf by our General Partner;

 

the cost of acquisitions, if any;

 

our ability to sell assets, if any, and the price that we may receive for such assets;

 

our debt service requirements and other liabilities, including the Deferred Purchase Price Obligation;

 

the amount of distributions on our preferred stock or the preferred stock of our subsidiaries;

 

fluctuations in our working capital needs;

 

our ability to borrow funds and access the debt and equity capital markets;

 

restrictions contained in our debt agreements;

 

the amount of cash reserves established by our General Partner;

 

not receiving anticipated shortfall payments from our customers;

 

adverse legal judgments, fines and settlements;

 

distributions paid on our Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A Preferred Units”); and

 

other business risks affecting our cash levels.

We depend on a relatively small number of customers for a significant portion of our revenues. For example, Caerus, a customer on our Piceance Basin gathering system, and Whiting, a customer on our Williston Basin gathering system, each account for over 10% of our aggregated revenue. The loss of, or material nonpayment or nonperformance by, or the curtailment of production by, any one or more of our customers could materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders.

Certain of our customers may have material financial and liquidity issues or may, as a result of operational incidents or other events, be disproportionately affected as compared to larger, better-capitalized companies. Any material nonpayment or nonperformance by any of our customers could have a material adverse effect on our revenues and cash flows and our ability to make cash distributions to our unitholders. We expect our exposure to concentrated risk of nonpayment or nonperformance to continue as long as we remain substantially dependent on a relatively small number of customers for a significant portion of our revenues.

If any of our customers curtail or reduce production in our areas of operation, it could reduce throughput on our system and, therefore, materially adversely affect our revenues, cash flows and ability to make cash distributions to our unitholders.

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Further, we are subject to the risk of non-payment or non-performance by our larger customers. We cannot predict the extent to which our customers’ business would be impacted if conditions in the energy industry deteriorate, nor can we estimate the impact such conditions would have on any of our customers’ ability to execute their drilling and development programs or perform under our gathering and processing agreements. The low commodity price environment has negatively impacted natural gas producers causing some producers in the industry significant economic stress, including, in certain cases, to file for bankruptcy protection or to renegotiate contracts. To the extent that any customer is in financial distress or commences bankruptcy proceedings, contracts with these customers may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. Any material non-payment or non-performance by our customers could adversely affect our business and operating results.

We are exposed to the creditworthiness and performance of our customers, suppliers and contract counterparties and any material nonpayment or nonperformance by one or more of these parties could materially adversely affect our financial and operating results.

Although we attempt to assess the creditworthiness and associated liquidity of our customers, suppliers and contract counterparties, there can be no assurance that our assessments will be accurate or that there will not be a rapid or unanticipated deterioration in their creditworthiness, which may have an adverse impact on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. In addition, there can be no assurance that our contract counterparties will perform or adhere to existing or future contractual arrangements, including making any required shortfall payments or other payments due under their respective contracts.

The policies and procedures we use to manage our exposure to credit risk, such as credit analysis, credit monitoring and, if necessary, requiring credit support, cannot fully eliminate counterparty credit risks. To the extent our policies and procedures prove to be inadequate, our financial and operational results may be negatively impacted.

Some of our counterparties may be highly leveraged, have limited financial resources and/or have recently experienced a rating agency downgrade and will be subject to their own operating and regulatory risks. Even if our credit review and analysis mechanisms work properly, we may experience financial losses in our dealings with such parties. In addition, volatility in commodity prices could have a negative impact on our counterparties, which, in turn, could have a negative impact on their ability to meet their obligations to us.

Any material nonpayment or nonperformance by any of our counterparties or suppliers could require us to pursue substitute counterparties or suppliers for the affected operations or reduce our operations. There can be no assurance that any such efforts would be successful or would provide similar financial and operational results.

Adverse developments in our areas of operation could materially adversely impact our financial condition, results of operations and cash flows and reduce our ability to make cash distributions to our unitholders.

Our operations are focused on gathering, treating and processing services in the following unconventional resource basins, primarily shale formations: the Utica Shale, the Williston Basin, the DJ Basin, the Permian Basin, the Piceance Basin, the Barnett Shale and the Marcellus Shale. Due to our limited industry diversity, adverse developments in the natural gas and crude oil industries or in our existing areas of operation could have a significantly greater impact than if we did not have such limited diversity on our financial condition, results of operations and cash flows.

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Significant prolonged weakness in natural gas, NGL and crude oil prices could reduce throughput on our systems and materially adversely affect our revenues and cash available to make cash distributions to our unitholders.

Lower natural gas, NGL and crude oil prices could negatively impact exploration, development and production of natural gas and crude oil, thereby resulting in reduced throughput on our gathering systems. Additionally, certain of our customers in each of our areas of operations have reduced, and others could reduce, drilling activity and capital expenditure budgets. If natural gas, NGL and/or crude oil prices remain at current levels or decrease, it could cause sustained reductions in exploration or production activity in our areas of operation and result in a further reduction in throughput on our systems, which could have a material adverse effect on our business, financial condition, results of operations and ability to make cash distributions to our unitholders.

Because of the natural decline in production from our customers' existing wells, our success depends in part on our customers replacing declining production and also on our ability to maintain levels of throughput on our systems. Any decrease in the volumes that we gather and process could materially adversely affect our business and operating results.

The customer volumes that support our business depend on the level of production from natural gas and crude oil wells connected to our systems, the production from which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our systems, we must obtain new sources of volume throughput. The primary factors affecting our ability to obtain new sources of volume throughput include (i) the level of successful drilling activity in our areas of operation and (ii) our ability to compete for new volumes on our systems.

We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over producers or their drilling and production decisions, which are affected by, among other things:

 

the availability and cost of capital;

 

prevailing and projected hydrocarbon commodity prices;

 

demand for crude oil, natural gas and other hydrocarbon products, including NGLs;

 

levels of reserves;

 

geological considerations;

 

environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

 

the availability of drilling rigs and other costs of production and equipment.

Fluctuations in energy prices can also greatly affect the development of new crude oil and natural gas reserves. Drilling and production activity generally decreases as commodity prices decrease. In general terms, the prices of crude oil, natural gas and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control. These factors include:

 

worldwide economic and geopolitical conditions;

 

global or national health concerns, including the outbreak of pandemic or contagious disease, such as the recent coronavirus, which may reduce demand for crude oil, natural gas and NGLs because of reduced global or national economic activity;

 

weather conditions and seasonal trends;

 

the levels of domestic production and consumer demand;

 

the availability of imported liquefied natural gas (“LNG”);

 

the ability to export LNG;

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the availability of transportation and storage systems with adequate capacity;

 

the volatility and uncertainty of regional pricing differentials and premiums;

 

the price and availability of alternative fuels, including alternative fuels that benefit from government subsidies;

 

the effect of energy conservation measures;

 

the nature and extent of governmental regulation and taxation; and

 

the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.

Because of these factors, even if new crude oil or natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain the current levels of throughput on our systems, those reductions could reduce our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.

In addition, it may be more difficult to maintain or increase the current volumes on our gathering systems, as several of the formations in the unconventional resource plays in which we operate generally have higher initial production rates and steeper production decline curves than wells in more conventional basins and may have steeper production decline curves than initially anticipated. Should we determine that the economics of our gathering, treating and processing assets do not justify the capital expenditures needed to grow or maintain volumes associated therewith, revenues associated with these assets will decline over time. In addition to capital expenditures to support growth, the steeper production decline curves associated with unconventional resource plays may require us to incur higher maintenance capital expenditures over time, which will reduce our cash available for distribution.

Many of our costs are fixed and do not vary with our throughput. These costs will not decline ratably or at all should we experience a reduction in throughput, which could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.

Any significant decrease in the demand for natural gas and crude oil could reduce the volumes of natural gas and crude oil that we gather and process, which could adversely affect our business and operating results.

The volumes of natural gas and crude oil that we gather and process depend on the supply and demand for natural gas and crude oil and other hydrocarbon products in the areas served by our assets. Natural gas and crude oil compete with other forms of energy available to users, including electricity, coal, other fuels and alternative energy. Increased demand for such forms of energy at the expense of natural gas and crude oil could lead to a reduction in demand for our services. Any such reduction could result in a decline in our revenues and cash flows and materially adversely affect our ability to make cash distributions to our unitholders.

If our customers do not increase the volumes they provide to our gathering systems, our ability to sustain cash distributions to our unitholders may be materially adversely affected.

If we are unsuccessful in attracting new customers and/or new gathering opportunities with existing customers, our ability to sustain cash distributions to our unitholders will be impaired. Our customers are not obligated to provide additional volumes to our gathering systems, and they may determine in the future that drilling activities in areas outside of our current areas of operation are strategically more attractive to them. Reductions by our customers in our areas of mutual interest could result in reductions in throughput on our systems and materially adversely impact our ability to sustain cash distributions to our unitholders.

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Certain of our gathering and processing agreements contain provisions that can reduce the cash flow stability that the agreements were designed to achieve.

We designed those gathering and processing agreements that contain MVC provisions to generate stable cash flows for us over the life of the MVC contract term while also minimizing our direct commodity price risk. Under certain of these MVCs, our customers agree to ship a minimum volume on our gathering systems or send a minimum volume to our processing plants or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. In addition, our gathering and processing agreements may also include an aggregate MVC, which represents the total amount that the customer must flow on our gathering system or send to our processing plants (or an equivalent monetary amount) over the MVC term. If such customer's actual throughput volumes are less than its MVC for the contracted measurement period, it must make a shortfall payment to us at the end of the applicable measurement period. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable fee. To the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period, certain of our gathering agreements contain provisions that allow the customer to use the excess volumes or the shortfall payment to credit against future excess volumes or future shortfall payments, which could have a material adverse effect on our results of operations, financial condition and cash flows and our ability to make cash distributions to our unitholders.

We have not obtained independent evaluations of all of the reserves connected to our gathering systems; therefore, in the future, customer volumes on our systems could be less than we anticipate.

We do not routinely obtain or update independent evaluations of the reserves connected to our systems. Moreover, even if we did obtain independent evaluations of all of the reserves connected to our systems, such evaluations may prove to be incorrect. Crude oil and natural gas reserve engineering requires subjective estimates of underground accumulations of crude oil and natural gas and assumptions concerning future crude oil and natural gas prices, future production levels and operating and development costs.

Accordingly, we may not have accurate estimates of total reserves dedicated to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our gathering systems are less than we anticipate and we are unable to secure additional volumes, it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our industry is highly competitive, and increased competitive pressure could materially adversely affect our business and operating results.

We compete with other midstream companies in our areas of operations, some of which are large companies that have greater financial, managerial and other resources than we do. In addition, some of our competitors may have assets in closer proximity to natural gas and crude oil supplies and may have available idle capacity in existing assets that would not require new capital investments for use. Our competitors may expand or construct gathering systems that would create additional competition for the services we provide to our customers. Because our customers do not have leases that cover the entirety of our areas of mutual interest, non-customer producers that lease acreage within any of our areas of mutual interest may choose to use one of our competitors for their gathering and/or processing service needs.

In addition, our customers may develop their own gathering systems outside of our areas of mutual interest. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flows could be materially adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.

Our gathering, treating and processing contracts have terms of various durations. As these contracts expire, we may have to negotiate extensions or renewals with existing customers or enter into new contracts with other customers. We may be unable to obtain new contracts on favorable commercial terms, if at all. We also may be unable to maintain the economic structure of a particular contract with an existing customer or the overall mix of our contract portfolio. Moreover, we may be unable to obtain areas of mutual interest from new customers in the future, and we may be unable to renew existing areas of mutual interest with current customers as and when they expire. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

 

the level of existing and new competition to provide gathering and/or processing services in our areas of operation;

 

the macroeconomic factors affecting gathering, treating and processing economics for our current and potential customers;

 

the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

 

the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and

 

the effects of federal, state or local regulations on the contracting practices of our customers.

To the extent we are unable to renew our existing contracts on terms that are favorable to us or successfully manage our overall contract mix over time, our revenues and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.

If third-party pipelines or other midstream facilities interconnected to our gathering systems become partially or fully unavailable, our revenues and cash flows and our ability to make cash distributions to our unitholders could be materially adversely affected.

Our gathering systems connect to third-party pipelines and other midstream facilities, such as processing plants, rail terminals and produced water disposal facilities. The continuing operation of such third-party pipelines and other midstream facilities is not within our control. These pipelines and other midstream facilities may become unavailable due to issues including, but not limited to, testing, turnarounds, line repair, reduced operating pressure, lack of operating capacity, regulatory requirements, curtailments of receipt or deliveries due to insufficient capacity or because of damage from other hazards. In addition, we do not have interconnect agreements with all of these pipelines and other facilities and the agreements we do have may be terminated in certain circumstances and/or on short notice. If any of these pipelines or other midstream facilities become unavailable for any reason, or, if these third parties are otherwise unwilling to receive or transport the natural gas, crude oil and produced water that we gather and/or process, our revenues, cash flows and ability to make cash distributions to our unitholders could be materially adversely affected.

We have a relatively limited ownership history with respect to certain of our assets. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines and/or processing facilities that could have a material adverse effect on our business and operating results.

We have a relatively limited history of operating certain of our assets. There may be historical occurrences or latent issues regarding certain of our pipeline systems of which we may be unaware and that may have a material adverse effect on our business and results of operations. Any significant increase in maintenance and repair expenditures or loss of revenue due to the condition of our pipeline systems could materially adversely affect our business and results of operations and our ability to make cash distributions to our unitholders.

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Crude oil and natural gas production and gathering may be adversely affected by weather conditions and terrain, which in turn could negatively impact the operations of our gathering, treating and processing facilities and our construction of additional facilities.

Extended periods of below freezing weather and unseasonably wet weather conditions, especially in North Dakota, Ohio and West Virginia, can be severe and can adversely affect crude oil and natural gas operations due to the potential shut-in of producing wells or decreased drilling activities. These types of interruptions could result in a decrease in the volumes supplied to our gathering systems. Further, delays and shutdowns caused by severe weather may have a material negative impact on the continuous operations of our gathering, treating and processing systems, including interruptions in service. These types of interruptions could negatively impact our ability to meet our contractual obligations to our customers and thereby give rise to certain termination rights and/or the release of dedicated acreage. Any resulting terminations or releases could materially adversely affect our business and results of operations.

We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our pipeline facilities are located in mountainous areas such as our Utica Shale and Marcellus Shale operations, which may require specially designed facilities and special installation considerations. If such facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant expenditures to correct or repair the deficiencies, or may incur significant damages to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damage to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines.

Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.

Our operations depend upon the infrastructure that we have developed and constructed. Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders.  Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

 

unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;

 

restrictions imposed by governmental authorities or court proceedings;

 

labor difficulties that result in a work stoppage or slowdown;

 

a disruption in the supply of resources necessary to operate our midstream facilities;

 

damage to our facilities resulting from production volumes that do not comply with applicable specifications; and

 

inadequate transportation and/or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity.  

Any significant interruption at any of our gathering, treating or processing facilities, or in our ability to provide gathering, treating or processing services, could adversely affect our operations and cash flows available for distribution to our unitholders.

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Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant incident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant incidents or events for which we are insured, our operations and financial results could be materially adversely affected.

Our operations are subject to all of the risks and hazards inherent in the operation of gathering, treating and processing systems, including:

 

damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;

 

inadvertent damage from construction, vehicles, farm and utility equipment;

 

leaks or losses resulting from the malfunction of equipment or facilities;

 

ruptures, fires and explosions; and

 

other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. The location of certain of our systems in or near populated areas, including residential areas, commercial business centers and industrial sites, could increase the damages resulting from these risks.

These risks may also result in curtailment or suspension of our operations. A natural disaster or any event such as those described above affecting the areas in which we and our customers operate could have a material adverse effect on our operations. Accidents or other operating risks could further result in loss of service available to our customers. Such circumstances, including those arising from maintenance and repair activities, could result in service interruptions on portions or all of our gathering systems. Potential customer impacts arising from service interruptions on segments of our gathering systems could include limitations on our ability to satisfy customer requirements, obligations to temporarily waive minimum volume commitments during times of constrained capacity, temporary or permanent release of production dedications, and solicitation of existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could materially adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business and results of operations and our ability to make cash distributions to our unitholders.

Our insurance coverage is provided by policies that cover us and Summit Investments. Therefore, it is possible that a claim by Summit Investments could exhaust insurance coverage and leave SMLP and its subsidiaries exposed to risk of loss should they experience a loss during the same policy cycle. In addition, although we have a range of insurance programs providing varying levels of protection for public liability, damage to property, loss of income and certain environmental hazards, we may not be insured against all causes of loss, claims or damage that may occur. If a significant incident or event occurs for which we are not fully insured, it could materially adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates and/or claims by Summit Investments may increase rates on all of the insured-asset group, including those owned by SMLP and its subsidiaries. As a result of industry or market conditions, some of which are beyond our control, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, with regard to the assets we have acquired, we have limited indemnification rights to recover from the seller of the assets in the event of any potential environmental liabilities.

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We may fail to successfully integrate gathering system acquisitions into our existing business in a timely manner, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders, or fail to realize all of the expected benefits of the acquisitions, which could negatively impact our future results of operations.

Integration of future gathering system acquisitions could be a complex, time-consuming and costly process, particularly if the acquired assets significantly increase our size and/or (i) diversify the geographic areas in which we operate or (ii) the service offerings that we provide.

The failure to successfully integrate the acquired assets with our existing business in a timely manner may have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. If any of the risks described above or in the immediately preceding risk factor or unanticipated liabilities or costs were to materialize with respect to future acquisitions or if the acquired assets were to perform at levels below the forecasts we used to evaluate them, then the anticipated benefits from the acquisition may not be fully realized, if at all, and our future results of operations and ability to make cash distributions to unitholders could be negatively impacted.

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could materially adversely affect our results of operations and financial condition.

The construction of new assets, including for example Double E, involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control.

Such construction projects may also require the expenditure of significant amounts of capital, and financing, traditional or otherwise, may not be available on economically acceptable terms or at all. If we undertake these projects, our revenue may not increase immediately upon the expenditure of funds for a particular project and they may not be completed on schedule, at the budgeted cost, or at all.

Moreover, we could construct facilities to capture anticipated future production growth in a region where such growth does not materialize or only materializes over a period materially longer than expected. To the extent we rely on estimates of future production in our decision to construct additions to our systems, such estimates may prove to be inaccurate due to the numerous uncertainties inherent in estimating quantities of future production. As a result, new facilities may not attract enough throughput to achieve our expected investment return, which could materially adversely affect our results of operations and financial condition.

In addition, the construction of additions or modifications to our existing gathering, treating and processing assets and the construction of new midstream assets may require us to obtain federal, state and local regulatory environmental or other authorizations. The approval process for gathering, treating and processing activities has become increasingly challenging, due in part to state and local concerns related to unregulated exploration and production and gathering, treating and processing activities in new production areas. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions. As a result, we may be unable to obtain such authorizations and may, therefore, be unable to connect new volumes to our systems or capitalize on other attractive expansion opportunities. A future government shutdown could delay the receipt of any federal regulatory approvals. Additionally, it may become more expensive for us to obtain authorizations or to renew existing authorizations. If the cost of renewing or obtaining new authorizations increases materially, our cash flows could be materially adversely affected.

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Limited access and/or availability of the debt and equity capital markets could impair our ability to grow or cause us to be unable to meet future capital requirements.

To expand our asset base, whether through acquisitions or organic growth, we will need to make expansion capital expenditures. We also frequently consider and enter into discussions with third parties regarding potential acquisitions. In addition, the terms of certain of our gathering and processing agreements also require us to spend significant amounts of capital, over a short period of time, to construct and develop additional midstream assets to support our customers' development projects. Depending on our customers' future development plans, it is possible that the capital required to construct and develop such assets could exceed our ability to finance those expenditures using our cash reserves or available capacity under our Revolving Credit Facility.

We plan to use cash from operations, incur borrowings and/or sell additional common units or other securities to fund our future expansion capital expenditures. Using cash from operations to fund expansion capital expenditures will directly reduce our cash available for distribution to unitholders. Our ability to obtain financing or to access the capital markets for future debt or equity offerings may be limited by (i) our financial condition at the time of any such financing or offering, (ii) covenants in our debt agreements, (iii) restrictions imposed by our Series A Preferred Units, (iv) general economic conditions and contingencies, (v) the impact of any secondary offering of common units by Summit Investments or the Sponsor, (vi) increasing disfavor among many investors towards investments in fossil fuel companies and (vii) general weakness in the debt and equity capital markets and other uncertainties that are beyond our control. In addition, lenders are facing increasing pressure to curtail their lending activities to companies in the oil and natural gas industry. Furthermore, we do not have a contractual commitment from our Sponsor or Summit Investments to provide any direct or indirect financial assistance to us. 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 expansion capital expenditures and acquisition capital expenditures with the issuance of additional equity. We recently announced our second large reduction in our common unit distribution in a year, and this reduction may further reduce demand for our common units. As such, if we are unable to raise expansion capital, we may lose the opportunity to make acquisitions, pursue new organic development projects, or to gather, treat and process new production volumes from our customers with whom we have agreed to construct and develop midstream assets in the future. Even if we are successful in obtaining external funds for expansion capital expenditures through the capital markets, the terms thereof could limit our ability to pay distributions to our common unitholders. In addition, incurring additional debt may significantly increase our interest expense and financial leverage, and issuing additional units representing limited partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution rate, which could materially decrease our ability to pay distributions at the then-current distribution rate.

Because our common units are yield-oriented securities, increases in interest rates could materially adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions to our unitholders.

Interest rates are generally near historic lows and may increase in the future. As with other yield-oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at our intended levels.

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We have a significant amount of indebtedness. Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects, and may limit our flexibility to obtain financing and to pursue other business opportunities.

At December 31, 2019, we had $1.48 billion of indebtedness outstanding and the unused portion of our $1.25 billion Revolving Credit Facility totaled $563.9 million. Based on covenant limits, our available borrowing capacity under the Revolving Credit Facility as of December 31, 2019 was approximately $100 million. See Note 10 of the notes to our consolidated financial statements included in Item 8 of this report for further discussion of our debt obligations, including debt maturities for the next five years and thereafter. Our existing and future debt services obligations could have significant consequences, including among other things:

 

limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms;

 

reducing our funds available for operations, future business opportunities and cash distributions to unitholders by that portion of our cash flow required to make interest payments on our debt;

 

increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and

 

limiting our flexibility in responding to changing business and economic conditions.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business and other factors, many of which are beyond our control, such as commodity prices and governmental regulation.

Restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, results of operations, ability to make cash distributions to unitholders and value of our common units.

We are dependent upon the earnings and cash flows generated by our operations to meet our debt service obligations and to make cash distributions to our unitholders. The operating and financial restrictions and covenants in our Revolving Credit Facility, our Senior Notes indentures and any future financing agreements could restrict our ability to finance future operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make cash distributions to our unitholders. For example, our Revolving Credit Facility and Senior Notes indentures, taken together, restrict our ability to, among other things:

 

incur or guarantee certain additional debt;

 

make certain cash distributions on or redeem or repurchase certain units;

 

make certain investments and acquisitions;

 

make certain capital expenditures;

 

incur certain liens or permit them to exist;

 

enter into certain types of transactions with affiliates;

 

enter into sale and lease-back transactions and certain operating leases;

 

merge or consolidate with another company or otherwise engage in a change of control transaction; and

 

transfer, sell or otherwise dispose of certain assets.

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Our Revolving Credit Facility and Senior Notes indentures also contain covenants requiring us to maintain certain financial ratios and meet certain tests. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot guarantee that we will meet those ratios and tests. Based upon the terms of SMLP’s revolving credit facility and total outstanding debt of $1.48 billion (inclusive of $800.0 million of senior unsecured notes), SMLP’s total leverage ratio and senior secured leverage ratio (as defined in the credit agreement) as of December 31, 2019, were 5.1 to 1.0 and 2.3 to 1.0, respectively, relative to maximum threshold limits of 5.5x and 3.75x.

The provisions of our Revolving Credit Facility and Senior Notes indentures may affect our ability to obtain future financing and pursue attractive business opportunities as well as affect our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Revolving Credit Facility or Senior Notes indentures could result in a default or an event of default that could enable our lenders and/or senior noteholders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, the lenders under our Revolving Credit Facility could proceed against the collateral granted to them to secure such debt. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment. The Revolving Credit Facility also has cross default provisions that apply to any other indebtedness we may have and the Senior Notes indentures have cross default provisions that apply to certain other indebtedness. Any of these restrictions in our Revolving Credit Facility and Senior Notes indentures could materially adversely affect our business, financial condition, cash flows and results of operations.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness or to refinance, which may not be successful.

Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Revolving Credit Facility and our Senior Notes, depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our operating cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to adopt alternative financing strategies, such as reducing or delaying investments and capital expenditures, selling assets, seeking additional capital or restructuring or refinancing our indebtedness, some or all of which may not be available to us on terms acceptable to us, if at all, or such alternative strategies may yield insufficient funds to make required payments on our indebtedness.

Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, including the market for senior unsecured notes, and our financial condition at the time. Any refinancing of our indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness on acceptable terms. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our Revolving Credit Facility and the indentures governing our Senior Notes place certain restrictions on our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions on terms acceptable to us, if at all, and the proceeds of any such dispositions may not be adequate to meet any debt service obligations then due.

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Further, if for any reason we are unable to meet our debt service and repayment obligations, we would be in default under the terms of the agreements governing our debt, which would allow our creditors under those agreements to declare all outstanding indebtedness thereunder to be due and payable (which would in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Revolving Credit Facility could terminate their commitments to extend credit, and the lenders could foreclose against our assets securing their borrowings and we could be forced into bankruptcy or liquidation. If the amounts outstanding under our Revolving Credit Facility or our Senior Notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full the amounts owed to our creditors.

A downgrade of our credit rating could impact our liquidity, access to capital and our costs of doing business, and independent third parties determine our credit ratings outside of our control.

A downgrade of our credit rating could increase our cost of borrowing under our Revolving Credit Facility and could require us to post collateral with third parties, including our hedging arrangements, which could negatively impact our available liquidity and increase our cost of debt. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we are experiencing significant working capital requirements or otherwise lacking liquidity, our results of operations, financial condition and cash flows could be adversely affected.

We have in the past and may in the future incur losses due to impairment in the carrying value of our long-lived assets or equity method investments.

We recorded long-lived asset impairments of $188.7 million, $7.2 million and $60.5 million in 2017, 2018 and 2019, respectively. In 2019, we also recorded an impairment of our equity method investment in Ohio Gathering of $329.7 million and a loss of $6.3 million related to a long-lived asset impairment on OCC. 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 long-lived assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. 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 either a market-based approach, an income-based approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows, or a mixture of both market- and income-based approaches. We evaluate our equity method investment for impairment whenever events or circumstances indicate that a decline in fair value is other than temporary. Any impairment determinations involve significant assumptions and judgments. If actual results are not consistent with our assumptions and estimates, or our assumptions and estimates change due to new information, we may be exposed to impairment charges. Adverse changes in our business or the overall operating environment, such as lower commodity prices, may affect our estimate of future operating results, which could result in future impairment due to the potential impact on our operations and cash flows.

Changes in the method of determining the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely affect interest expense related to outstanding debt.

Amounts drawn under our current debt agreements, including the Revolving Credit Facility, may bear interest at rates based on LIBOR. On July 27, 2017, the Financial Conduct Authority in the United Kingdom announced that it would phase out LIBOR as a benchmark by the end of 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The Revolving Credit Facility does not provide for a mechanism to reflect the establishment of an alternative rate of interest upon the phase-out of LIBOR. Under the Revolving Credit Facility, if the agent is unable to determine LIBOR, all existing LIBOR loans will convert to base rate loans at the end of their respective interest periods, and we will only have access to these base rate loans. We have not yet pursued any technical amendment or other contractual alternative to address this matter and are currently evaluating the impact of the potential replacement of the LIBOR interest rate. In addition, the overall financial markets may be disrupted as a result of the phase-out or replacement of LIBOR. Uncertainty as to the nature of such potential phase-out and alternative reference rates or disruption in the financial market could have a material adverse effect on our financial condition, results of operations and cash flows.

A portion of our revenues are directly exposed to changes in crude oil, natural gas and NGL prices, and our exposure may increase in the future.

During the year ended December 31, 2019, we derived 20% of our revenues 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. Consequently, our existing operations and cash flows have direct exposure to commodity price risk. Although we will seek to limit our commodity price exposure with new customers in the future, our efforts to obtain fee-based contractual terms may not be successful or the local market for our services may not support fee-based gathering and processing agreements. For example, we have

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percent-of-proceeds contracts with certain natural gas producer customers and we may, in the future, enter into additional percent-of-proceeds contracts with these customers or other customers or enter into keep-whole arrangements, which would increase our exposure to commodity price risk, as the revenues generated from those contracts directly correlate with the fluctuating price of the underlying commodities.

Furthermore, we may acquire or develop additional midstream assets in the future that have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas and crude oil prices could have a material adverse effect on our business, results of operations and financial condition.  For example, for a small portion of the natural gas gathered on our systems, we purchase natural gas from producers prior to delivering the natural gas to pipelines where we typically resell the natural gas under arrangements including sales at index prices. Generally, the gross margins we realize under these arrangements decrease in periods of low natural gas prices. If we expand the implementation of such natural gas purchase and sale arrangements within our business, such fluctuations could materially affect our business.

A change in laws and regulations applicable to our assets or services, or the interpretation or implementation of existing laws and regulations may cause our revenues to decline or our operation and maintenance expenses to increase.

Various aspects of our operations are subject to regulation by the various federal, state and local departments and agencies that have jurisdiction over participants in the energy industry. The regulation of our activities and the natural gas and crude oil industries frequently change as they are reviewed by legislators and regulators. In 2016, the North Dakota Industrial Commission adopted rule changes that resulted in additional construction and monitoring requirements for certain underground gathering pipelines, including, but not limited to, those that transport produced water. The NDIC also adopted reclamation bonding requirements for certain underground gathering pipelines. In July 2018, PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. In November 2018, PHMSA also increased the maximum penalties for violating federal safety standards, which are subject to future increases to account for inflation. In October 2019, PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in integrity management, and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. In addition, the adoption of proposals for more stringent legislation, regulation or taxation of drilling activity could directly curtail such activity or increase the cost of drilling, resulting in reduced levels of drilling activity and therefore reduced demand for our services. For example, in 2018 the Colorado state ballot included a proposed 2,500 foot setback for oil and gas development from occupied structures and certain other areas. While the proposal did not pass, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. Regulatory agencies establish and, from time to time, change priorities, which may result in additional burdens on us, such as additional reporting requirements and more frequent audits of operations. Our operations and the markets in which we participate are affected by these laws, regulations and interpretations and may be affected by changes to them or their implementation, which may cause us to realize materially lower revenues or incur materially increased operation and maintenance costs or both.

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Increased regulation of hydraulic fracturing could result in reductions or delays in customer production, which could materially adversely impact our revenues.

Hydraulic fracturing is an important and increasingly common practice that is used to stimulate production of natural gas and/or crude oil from dense subsurface rock formations, and is primarily regulated by state agencies. However, Congress has in the past, and may in the future consider legislation to regulate hydraulic fracturing by federal agencies. Many states have already adopted laws and/or regulations that require disclosure of the chemicals used in hydraulic fracturing. A number of states have adopted, and other states are considering adopting, legal requirements that could impose more stringent permitting, disclosure and well construction requirements on crude oil and/or natural gas drilling activities. For example, a Colorado ballot initiative, Proposition 112, would have substantially increased setback distances for various upstream activities, thereby substantially restricting new oil and gas development in the state. Although Proposition 112 was defeated in the November 2018 elections, similar ballot initiatives have recently been circulated by interested groups for potential consideration in upcoming elections, although none have yet obtained the requisite number of signatures. Further, Colorado Senate Bill 19-181, signed into law in April 2019, changed the mandate of the state’s oil and gas regulator from fostering oil and gas development to regulating oil and gas development in a reasonable manner to protect public health and the environment. The new law also allows local governments to impose more restrictive requirements on oil and gas operations than those issued by the state. Similar efforts in Colorado and elsewhere could restrict oil and gas development in the future. States also could elect to prohibit hydraulic fracturing altogether, as New York, Maryland, and Vermont have done. In addition, certain local governments have adopted, and additional local governments may adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular.

The EPA has also moved forward with various regulatory actions, including approving new regulations requiring green completions of hydraulically-fractured wells and corresponding reporting requirements (NSPS OOOO) that went into effect in 2015. Revisions to the green completion regulations (NSPS OOOOa) were finalized in June 2016 and include additional requirements to reduce methane and VOCs. In October 2018, the EPA published a proposed rule that would amend certain requirements of NSPS OOOOa. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and clarify and streamline certain other requirements. In September 2019, the EPA published another rule proposing amendments to the June 2016 rule that would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. However, the 2016 regulations currently remain in effect. The BLM has also asserted regulatory authority over aspects of the hydraulic fracturing process, and issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. However, in December 2017, the BLM published a final rule rescinding the 2015 rule. The rescission rule is currently subject to a legal challenge. Further, several federal governmental agencies have conducted reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. The results of such reviews or studies could spur initiatives to further regulate hydraulic fracturing.

State and federal regulatory agencies recently have focused on a possible connection between the hydraulic fracturing related activities and the increased occurrence of seismic activity. When caused by human activity, such events are called induced seismicity. Some state regulatory agencies, including those in Colorado, Ohio, and Texas, have modified their regulations or guidance to account for induced seismicity. These developments could result in additional regulation and restrictions on the use of injection disposal wells and hydraulic fracturing. Such regulations and restrictions could cause delays and impose additional costs and restrictions on our customers.

If new or more stringent federal, state or local legal restrictions relating to drilling activities or to the hydraulic fracturing process are adopted, this could result in a reduction in the supply of natural gas and/or crude oil that our customers produce, and could thereby adversely affect our revenues and results of operations. Compliance with such rules could also generally result in additional costs, including increased capital expenditures and operating costs, for our customers, which could ultimately decrease end-user demand for our services and could have a material adverse effect on our business.

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We are subject to FERC jurisdiction, federal anti-market manipulation laws and regulations, potentially other federal regulatory requirements and state and local regulation, and could be materially affected by changes in such laws and regulations, or in the way they are interpreted and enforced.

We believe that our natural gas pipeline facilities qualify as gathering facilities that are exempt from the jurisdiction of FERC under the NGA and the NGPA. Interstate movements of crude oil on the Epping Pipeline in North Dakota are subject to FERC jurisdiction under the ICA, and the rates, terms and conditions of service, and practices on the pipeline are subject to review and challenge before FERC. Additionally, our proposed Double E Project, which is currently under consideration by FERC in Docket No. CP19-495-000, and is anticipated to provide natural gas transmission service from southeastern New Mexico to the Waha Hub in Texas, will be subject to FERC jurisdiction once approved. FERC may include conditions on its issuance of the certificate that make a project impracticable or too costly, or may ultimately determine not to issue the certificate required for us to pursue the project. Typically, a pipeline project requires review by a number of governmental agencies, including FERC, and other federal, state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any delay or refusal by an agency to issue authorizations or permits as requested for the project may mean that they will be constructed in a manner or with capital requirements that we did not anticipate or that we will not be able to pursue the project. Such delay, modification or refusal could materially and negatively impact the additional revenues expected from the project. In addition to approving and regulating the construction and operation of interstate natural gas pipelines, FERC also regulates such pipelines’ rates and terms and conditions of service, including transportation service agreements and negotiated rate agreements.

We are also generally subject to the anti-market manipulation provisions in the NGA, as amended by the Energy Policy Act of 2005, and to FERC's regulations thereunder, which authorize FERC to impose fines of up to $1,291,894 per day per violation of the NGA or its implementing regulations, subject to future adjustment for inflation. In addition, the FTC holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in oil markets, and has adopted broad rules and regulations prohibiting fraud and market manipulation. The FTC is also authorized to seek fines of up to $1,231,690 per violation, subject to future adjustment for inflation. The CFTC is directed under the CEA to prevent price manipulation in the commodity, futures and swaps markets, including the energy markets. Pursuant to the Dodd-Frank Act, and other authority, the CFTC has adopted additional anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity, futures and swaps markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,212,866 per violation, subject to future adjustment for inflation, or triple the monetary gain to the violator for each violation of the anti-market manipulation provisions of the CEA.

The distinction between federally unregulated natural gas and crude oil pipelines and FERC-regulated natural gas and crude oil pipelines has been the subject of extensive litigation and is determined by FERC on a case-by-case basis. FERC has made no determinations as to the status of our facilities. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by FERC, Congress or the courts. If our natural gas gathering operations or crude oil operations beyond the Epping Pipeline become subject to FERC jurisdiction under the NGA, the NGPA or the ICA, the result may materially adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of our gathering agreements with our customers. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA, the NGPA or the ICA, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such services in excess of the rate established by FERC.

We are subject to state and local regulation regarding the construction and operation of our gathering, treating and processing systems, as well as state ratable take statutes and regulations. Regulation of the construction and operation of our facilities may affect our ability to expand our facilities or build new facilities and such regulation may cause us to incur additional operating costs or limit the quantities of natural gas and crude oil we may gather, treat and process. Ratable take statutes and regulations generally require gatherers to take natural gas and crude oil production that may be tendered for gathering without undue discrimination. These requirements restrict our right to decide whose production we gather, treat and process. Many states have adopted complaint-based regulation of gathering, treating and processing activities, which allows producers and shippers to file complaints with state regulators in an effort to resolve access issues, rate grievances and other matters. Other state and municipal

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regulations do not directly apply to our business, but may nonetheless affect the availability of natural gas and crude oil for gathering, treating and processing, including state regulation of production rates, maximum daily production allowable from wells, and other activities related to drilling and operating wells. While our facilities currently are subject to limited state and local regulation, there is a risk that state or local laws will be changed or reinterpreted, which may materially affect our operations, operating costs and revenues.

Recent actions by the FERC may affect rates on Epping Pipeline and other future FERC-regulated pipelines.

On March 15, 2018, FERC announced a revised policy prohibiting FERC-jurisdictional natural gas and liquids pipelines owned by master limited partnerships from including an allowance for income taxes in the cost of service used to calculate tariff rates. Most of our pipelines are not subject to FERC regulation and so will not be affected by the revised policy statement. However, rates for interstate movements of crude oil on our Epping Pipeline in North Dakota and any future FERC-regulated pipelines may be affected by the application of the revised policy statement in subsequent FERC proceedings.

FERC has not required regulated interstate oil pipelines to decrease their rates on an industry-wide basis to implement the new policy. However, FERC stated that the effects of the revised policy statement must be incorporated in annual FERC financial reports made by regulated interstate oil pipelines. These reports, which will also reflect the impact of the corporate income tax reduction enacted as part of the Tax Cuts and Jobs Act of 2017, will be used in FERC’s next five-year review and determination of the index rate adjustment, which will occur in 2020 and will become effective on July 1, 2021. The impact of these future proceedings on Epping Pipeline and any future FERC-regulated pipelines is uncertain at this time.

Until FERC sets the next index rate adjustment, Epping Pipeline and any future FERC-regulated pipelines may face an increased risk of shipper complaints seeking FERC review of its rates. FERC can also initiate review of rates on its own initiative. We could also propose new cost-of-service rates or changes to our existing rates that would be subject to review by FERC under its new policy. No such proceedings have occurred at this time, however, and the potential outcome of any such proceedings, should any materialize, is uncertain. As a result of any such proceedings, Epping Pipeline and any future FERC-regulated pipelines may be required to modify their rates, which could affect the revenues we generate with our Epping Pipeline and any future FERC-regulated pipelines. At this time, we do not expect any such proceedings would have a material adverse effect, but we intend to monitor FERC developments and provide updated disclosure, as necessary.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

Our gathering, treating and processing operations are subject to stringent and complex federal, state and local environmental laws and regulations, including laws and regulations regarding the discharge of materials into the environment or otherwise relating to environmental protection, including, for example, the CAA, CERCLA, the CWA, the OPA, the RCRA, the Endangered Species Act and the Toxic Substances Control Act.

These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our pipelines and facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. For additional information on specific laws and regulations, see the "Environmental Matters—Air Emissions" section of Item 1. Business. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply with these laws, regulations and requisite permits may result in the assessment of significant administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue.

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There is a risk that we may incur significant environmental costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of hydrocarbons and other wastes and potential emissions and discharges related to our operations. Joint and several, strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, many of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the properties through which our gathering systems pass, and on which certain of our facilities are located, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. For example, an accidental release from one of our pipelines could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners and other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. In addition, changes in environmental laws occur frequently, and any such changes that result in additional permitting obligations or more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our operations or financial position. We may not be able to recover all or any of these costs from insurance.

The 2020 presidential and congressional elections may result in a change in administration and control of Congress with the potential consequence of increased restrictions on oil and gas production activities, which could materially adversely affect our industry and our financial condition and results of operations.

We may incur greater than anticipated costs and liabilities as a result of pipeline safety requirements.

The DOT, through PHMSA, has adopted and enforces safety standards and procedures applicable to our pipelines. In addition, many states, including the states in which we operate, have adopted regulations that are identical to or more restrictive than existing DOT regulations for intrastate pipelines. Among the regulations applicable to us, PHMSA requires pipeline operators to develop integrity management programs for certain pipelines located in high consequence areas, which include high population areas such as the Dallas-Fort Worth greater metropolitan area where our DFW Midstream system is located. While the majority of our pipelines meet the DOT definition of gathering lines and are thus currently exempt from PHMSA's integrity management requirements, we also operate a limited number of pipelines that are subject to the integrity management requirements. The regulations require operators, including us, to:

 

perform ongoing assessments of pipeline integrity;

 

identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

 

maintain processes for data collection, integration and analysis;

 

repair and remediate pipelines as necessary;

 

adopt and maintain procedures, standards and training programs for control room operations; and

 

implement preventive and mitigating actions.

For additional information on PHMSA regulations relating to pipeline safety, see the "Regulation of the Natural Gas and Crude Oil Industries—Safety and Maintenance" section of Item 1. Business.

In July 2018, the PHMSA issued an advance notice of proposed rulemaking seeking comment on the class location requirements for natural gas transmission pipelines, and particularly the actions operators must take when class locations change due to population growth or building construction near the pipeline. In October 2019, the PHMSA issued three new final rules. One rule establishes procedures to implement the expanded emergency order enforcement authority set forth in an October 2016 interim final rule. Among other things, this rule allows the PHMSA to issue an emergency order without advance notice or opportunity for a hearing. The other two rules impose several new requirements on operators of onshore gas transmission systems and hazardous liquids pipelines. The rule concerning gas transmission extends the requirement to conduct integrity assessments beyond “high consequence areas” (HCAs) to pipelines in “moderate consequence areas” (MCAs). It also includes requirements to reconfirm Maximum Allowable Operating Pressure (MAOP), report MAOP exceedances, consider seismicity as a risk factor in

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integrity management, and use certain safety features on in-line inspection equipment. The rule concerning hazardous liquids extends the required use of leak detection systems beyond HCAs to all regulated non-gathering hazardous liquid pipelines, requires reporting for gravity fed lines and unregulated gathering lines, requires periodic inspection of all lines not in HCAs, calls for inspections of lines after extreme weather events, and adds a requirement to make all lines in or affecting HCAs capable of accommodating in-line inspection tools over the next 20 years. While we believe that we are in compliance with existing safety laws and regulations, increased penalties for safety violations and potential regulatory changes could have a material adverse effect on our operations, operating and maintenance expenses and revenues.

Climate change legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the services we provide.

In recent years, the U.S. Congress has considered legislation to restrict or regulate emissions of GHGs, such as carbon dioxide and methane that may be contributing to global warming. It presently appears unlikely that comprehensive climate legislation will be passed by either house of Congress in the near future, although energy legislation and other initiatives are expected to be proposed that may be relevant to GHG emissions issues. For example, the revisions to the NSPS found in 40 CFR 60 subpart OOOO (and OOOOa) include GHG emission reduction requirements. However, in October 2018, the EPA published a proposed rule that would amend certain requirements of NSPS OOOOa. Among other things, the proposed rule would reduce monitoring frequencies for fugitive emissions and clarify and streamline certain other requirements. In September 2019, the EPA published proposed amendments to the rule that would remove sources in the transmission and storage segments from the regulated source category and would rescind the application of the NSPS and methane-specific requirements to these sources. The 2016 regulation currently remains in effect.

In addition, almost half of the states, either individually or through multi-state regional initiatives, have begun to address GHG emissions, primarily through the planned development of emission inventories or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and surrender emission allowances. In general, the number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved. Depending on the scope of a particular program, we could be required to purchase and surrender allowances for GHG emissions resulting from our operations (e.g., at compressor stations). Although most of the state-level initiatives have to date been focused on large sources of GHG emissions, such as electric power plants, it is possible that certain components of our operations, such as our gas-fired compressors, could become subject to state-level GHG-related regulation. For example, in January 2019, the governor of New Mexico signed an executive order that includes a goal of reducing statewide GHG emissions by at least 45% by 2030. The executive order directs the New Mexico Energy, Minerals and Natural Resources Department (“EMNRD”) and the New Mexico Environment Department (“NMED”) to jointly develop a statewide, enforceable regulatory framework to secure reductions in oil and gas sector methane emissions. The executive order also creates a Climate Change Task Force to evaluate and develop regulatory strategies to reach the 45% reduction goal. Although we cannot currently determine the effect of a potential regulatory framework developed by the ENMRD and the NMED or potential regulatory strategies that may be suggested by the Climate Change Task Force, if implemented they could be material to the business, reputation, financial condition or results of operations of our Summit Permian system.

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Independent of Congress, the EPA has adopted regulations under its existing CAA authority. In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA adopted regulations that, among other things, establish PSD construction and Title V operating permit reviews for certain large stationary sources of GHG emissions. For additional information on EPA regulations adopted under the CAA, see the "Environmental Matters—Climate Change" section of Item 1. Business.  Further, in December 2015, over 190 countries, including the United States, reached an agreement to reduce global GHG emissions. The agreement entered into force in November 2016 after over 70 countries, including the United States, ratified or otherwise consented to be bound by the agreement. In November 2019, the United States submitted formal notification to the United Nations that it intends to withdraw from the agreement. The earliest possible effective withdrawal date from the agreement is November 2020. However, if and to the extent the United States implements this agreement, it could have a material adverse effect on our business and that of our customers.

Although it is not possible at this time to accurately estimate how potential future laws or regulations addressing GHG emissions would impact our business, either directly or indirectly, any future federal or state laws or implementing regulations that may be adopted to address GHG emissions could require us to incur increased operating costs and could materially adversely affect demand for our services. The potential increase in the costs of our operations resulting from any legislation or regulation to restrict emissions of GHG could include new or increased costs to operate and maintain our facilities, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions, adhere to alternative energy requirements and administer and manage a GHG emissions program. While we may be able to include some or all of such increased costs in the rates we charge, such recovery of costs is uncertain. Moreover, incentives to conserve energy or use alternative energy sources could reduce demand for our services. We cannot predict with any certainty at this time how these possibilities may affect our operations.

The implementation of statutory and regulatory requirements for swap transactions could have an adverse impact on our ability to hedge risks associated with our business and increase the working capital requirements to conduct these activities.

Congress adopted comprehensive financial reform legislation under the Dodd-Frank Act that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. This legislation requires the CFTC and the SEC and other regulatory authorities to promulgate certain rules and regulations, including rules and regulations relating to the regulation of certain swaps market participants, such as swap dealers, the clearing of certain swaps through central counterparties, the execution of certain swaps on designated contract markets or swap execution facilities, mandatory margin requirements for uncleared swaps, and the reporting and recordkeeping of swaps. While most of the regulations have been promulgated and are already in effect, the rulemaking and implementation process is still ongoing. Moreover, CFTC continues to refine its initial rulemakings under the Dodd-Frank Act. As a result, we cannot yet predict the ultimate effect of the rules and regulations on our business and while most of the regulations have been adopted, any new regulations or modifications to existing regulations could increase the cost of derivative contracts, limit the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties.

The CFTC has proposed federal position limits on certain core futures and equivalent swaps contracts in the major energy and other markets, with exceptions for certain bona fide hedging transactions provided that various conditions are satisfied. If finalized, the position limits rule and its companion rule on aggregation among entities under common ownership or control may have an impact on our ability to hedge our exposure to certain enumerated commodities.

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In 2013, the CFTC implemented final rules regarding mandatory clearing of certain classes of interest rate swaps and certain classes of index credit default swaps. Mandatory trading on designated contract markets or swap execution facilities of certain interest rate swaps and index credit default swaps also began in 2014. At this time, the CFTC has not proposed any rules designating other classes of swaps, including physical commodity swaps, for mandatory clearing. The CFTC and prudential banking regulators also recently adopted mandatory margin requirements on uncleared swaps between swap dealers and certain other counterparties. Although we may qualify for a commercial end-user exception from the mandatory clearing, trade execution and uncleared swaps margin requirements, mandatory clearing and trade execution requirements and uncleared swaps margin requirements applicable to other market participants, such as swap dealers, may affect the cost and availability of the swaps that we use for hedging.

Under the Dodd-Frank Act, the CFTC is also directed generally to prevent price manipulation and fraud in the following two markets: (a) physical commodities traded in interstate commerce, including physical energy and other commodities, as well as (b) financial instruments, such as futures, options and swaps. Pursuant to the Dodd-Frank Act, the CFTC has adopted additional anti-market manipulation, anti-fraud and disruptive trading practices regulations that prohibit, among other things, fraud and price manipulation in the physical commodities, futures, options and swaps markets. Should we violate these laws and regulations, we could be subject to CFTC enforcement action and material penalties, and sanctions.

We currently enter into forward contracts with third parties to buy power and sell natural gas in an attempt to mitigate our exposure to fluctuations in the price of natural gas with respect to those volumes. The CFTC has finalized an interpretation clarifying whether certain forwards with volumetric optionality are regulated as forwards or qualify as options on commodities and therefore swaps. This interpretation may have an impact on our ability to enter into certain forwards or may impose additional requirements with respect to certain transactions.

In addition to the Dodd-Frank Act, the European Union and other foreign regulators have adopted and are implementing local reforms generally comparable with the reforms under the Dodd-Frank Act. Implementation and enforcement of these regulatory provisions may reduce our ability to hedge our market risks with non-U.S. counterparties and may make any transactions involving cross-border swaps more expensive and burdensome.  Additionally, the lack of regulatory equivalency across jurisdictions may increase compliance costs and make it more costly to satisfy regulatory obligations.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

We do not own all of the land on which our pipelines and facilities have been constructed, and we are, therefore, subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if such rights-of-way lapse or terminate or if our pipelines are not properly located within the boundaries of such rights-of-way. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies either perpetually or for a specific period of time. If we were to be unsuccessful in renegotiating rights-of-way, we might have to relocate our facilities. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Terrorist attacks and threats, escalation of military activity in response to these attacks or acts of war could have a material adverse effect on our business, financial condition or results of operations.

Terrorist attacks and threats, escalation of military activity or acts of war may have significant effects on general economic conditions, fluctuations in consumer confidence and spending and market liquidity, each of which could materially and adversely affect our business. Future terrorist attacks, rumors or threats of war, actual conflicts involving the United States or its allies, or military or trade disruptions may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. Disruption or significant increases in energy prices could result in government-imposed price controls. It is possible that any of these occurrences, or a combination of them, could have a material adverse effect on our business, financial condition and results of operations. Our insurance may not protect us against such occurrences.

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We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from various groups.

We may face opposition to the development, permitting, construction or operation of our pipelines and facilities from environmental groups, landowners, local groups and other advocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory or administrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the development or operation of our assets and business. For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resist our efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or other facility for a period of time that is significantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury to people, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by our operations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to our unitholders and, accordingly, have a material adverse effect on our business, financial condition and results of operations. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we require to conduct our operations to be withheld, delayed or burdened by requirements that restrict our ability to profitably conduct our business.

Recently, activists concerned about the potential effects of climate change have directed their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain an increasing number of financial institutions, funds, individual investors and other sources of capital restricting or eliminating their investment in fossil fuel-related activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities or energy infrastructure related projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.

Our operations depend on the use of information technology ("IT") systems that could be the target of a cyberattack.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations, including certain midstream activities. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems now control large scale processes that can include multiple sites and long distances, such as oil and gas pipelines.

Our operations depend on the use of sophisticated IT systems. Our IT systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of sensitive or proprietary information as well as disrupt our operations, damage our reputation or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. In addition, certain cyber-incidents, such as surveillance, may remain undetected for an extended period. We may be required to incur additional costs to modify or enhance our IT systems or to prevent or remediate any such attacks.

A cyber-incident involving our IT systems and related infrastructure, or that of our customers, venders and counterparties, could disrupt our business plans and negatively impact our operations in the following ways, among others:

 

a cyber-attack on a vendor or service provider could result in supply chain disruptions, which could delay or halt development of additional infrastructure, effectively delaying the start of cash flows from the project;

 

a cyber-attack on downstream pipelines could prevent us from delivering product at the tailgate of our facilities, resulting in a loss of revenues;

 

a cyber-attack on a communications network or power grid could cause operational disruption, resulting in loss of revenues;

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a deliberate corruption of our financial or operational data could result in events of non-compliance, which could lead to regulatory fines or penalties; and

 

business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation or a negative impact on the price of our units.

Our business is subject to complex and evolving U.S. and International laws and regulations regarding privacy and data protection (“data protection laws”). Many of these laws and regulations are subject to change and uncertain interpretation, and could result in claims, increased cost of operations or otherwise harm our business.

Along with our own data and information in the normal course of our business, we and our partners collect and retain significant volumes of certain types of data, some of which are subject to specific laws and regulations. The transfer and use of this data both domestically and across international borders is becoming increasingly complex. The regulatory environment surrounding and the transfer and protection of such data is constantly evolving and can be subject to significant change. New data protection laws at the federal, state, international, national, provincial and local levels, including recent Colorado legislation, the European Union General Data Protection Regulation (“GDPR”) and the California Consumer Privacy Act (“CCPA”), pose increasingly complex compliance challenges and potentially elevate our costs.

Complying with these jurisdictional requirements could increase the costs and complexity of compliance, and violations of applicable data protection laws can result in significant penalties. For example, the GDPR applies to activities regarding personal data that may be conducted by us, directly or indirectly through vendors and subcontractors, from an establishment in the European Union. Failure to comply could result in significant penalties of up to a maximum of 4% of our global turnover that may materially adversely affect our business, reputation, results of operations, and cash flows. Similarly, the CCPA, which came into effect on January 1, 2020, gives California residents specific rights in relation to their personal information, requires that companies take certain actions, including notifications for security incidents and may apply to activities regarding personal information that is collected by us, directly or indirectly, from California residents. As interpretation and enforcement of the CCPA evolves, it creates a range of new compliance obligations, which could cause us to change our business practices, with the possibility for significant financial penalties for noncompliance that may materially adversely affect our business, reputation, results of operations, and cash flows.

As noted above, we are also subject to the possibility of information security breaches, which themselves may result in a violation of these laws. Additionally, if we acquire a company that has violated or is not in compliance with applicable data protection laws, we may incur significant liabilities and penalties as a result.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key personnel.

Our ability to operate our business and implement our strategies depends on our continued ability to attract and retain highly skilled personnel with midstream energy industry experience and competition for these persons in the midstream energy industry is intense. Given our size, we may be at a disadvantage, relative to our larger competitors, in the competition for these personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract our senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

A shortage of skilled labor in the midstream energy industry could reduce employee productivity and increase costs, which could have a material adverse effect on our business and results of operations.

The operation of gathering, treating and processing systems requires skilled laborers in multiple disciplines such as equipment operators, mechanics and engineers, among others. We have from time to time encountered shortages for these types of skilled labor. If we experience shortages of skilled labor in the future, our labor and overall productivity or costs could be materially adversely affected. If our labor prices increase or if we experience materially increased health and benefit costs with respect to our General Partner's employees, our business and results of operations and our ability to make cash distributions to our unitholders could be materially adversely affected.

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Risks Inherent in an Investment in Us

Summit Investments indirectly owns and controls our General Partner, which has sole responsibility for conducting our business and managing our operations and limited duties to us and our unitholders. Our General Partner and its affiliates have conflicts of interest with us and they may favor their own interests to the detriment of us and our unitholders.

Summit Investments controls our General Partner and has authority to appoint all of the officers and directors of our General Partner, some of whom are officers, directors or principals of Energy Capital Partners, the entity that controls Summit Investments. Although our General Partner has a duty to manage us in a manner that is in our best interests, the directors and officers of our General Partner also have a duty to manage our General Partner in a manner that is in the best interests of its owner. Conflicts of interest will arise between Summit Investments and its owners and our General Partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our General Partner may favor its own interests and the interests of Summit Investments and its owners over our interests and the interests of our unitholders. These conflicts include the following situations, among others:

 

Neither our Partnership Agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of their investment and growth to areas not served by our assets;

 

Summit Investments is not limited in its ability to compete with us and in the future may offer business opportunities to third parties without first offering us the right to bid for them;

 

Our General Partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest;

 

Our Partnership Agreement replaces the fiduciary duties that would otherwise be owed by our General Partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our General Partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty;

 

Except in limited circumstances, our General Partner has the power and authority to conduct our business without unitholder approval;

 

Our General Partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

Our General Partner determines which costs incurred by it are reimbursable by us;

 

Our Partnership Agreement does not restrict our General Partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

 

Our General Partner intends to limit its liability regarding our contractual and other obligations;

 

Our General Partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;

 

Our General Partner controls the enforcement of the obligations that it and its affiliates owe to us; and

 

Our General Partner decides whether to retain separate counsel, accountants or others to perform services for us.

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Our general partner interest or the control of our General Partner may be transferred to a third party without unitholder consent.

If Energy Capital Partners, the private equity firm that controls Summit Investments, consummates a transaction involving a sale or other disposition of its interests in Summit Investments, the transaction would result in a change of control of SMLP because Summit Investments indirectly owns and controls our General Partner. In addition, our General Partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our Partnership Agreement does not restrict the ability of Summit Investments to transfer all or a portion of its ownership interest in our General Partner to a third party. The owner of Summit Investments, or new members of our General Partner, as applicable, would then be in a position to replace the Board of Directors and officers of our General Partner with their own designees and thereby exert significant control over the decisions made by the Board of Directors and officers. This effectively permits a change of control without the vote or consent of the unitholders.

The equity interests in our General Partner are pledged as collateral for SMP Holdings’ senior secured term loan facility; in the event SMP Holdings is unable to meet its obligations under that term loan facility, including as a result of a reduction in the amount, or elimination, of the distributions we pay to our unitholders, or is subject to certain bankruptcy or insolvency related events, SMP Holdings’ lenders may gain control of our general partner.

On March 21, 2017, SMP Holdings entered into a term loan agreement, which we refer to as the SMP Holdings Term Loan Facility. SMP Holdings’ ownership interest in our general partner is subject to a lien under the SMP Holdings Term Loan Facility. In the event SMP Holdings is unable to satisfy its obligations under the SMP Holdings Term Loan Facility, including as a result of a reduction in the amount, or elimination, of the distributions we pay to our unitholders, including SMP Holdings, and the lenders foreclose on the collateral securing such obligations, the lenders will own our general partner, and effectively all of its assets, which include the general partner interest in us.  In such event, SMP Holdings’ lenders would own the entity that controls our management and operation. Moreover, in the event SMP Holdings becomes insolvent or is declared bankrupt, our general partner also may be deemed insolvent or declared bankrupt. Under the terms of our partnership agreement, certain bankruptcy or insolvency related events of our general partner may cause a dissolution of our partnership.

Our Sponsor is not limited in its ability to compete with us and is not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could materially adversely affect our results of operations and cash available for distribution to our unitholders.

Although it controls Summit Investments, our Sponsor may compete with us for investment opportunities and may own interests in entities that compete with us. Our Sponsor is not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, our Sponsor and Summit Investments may acquire, construct or dispose of additional midstream or other assets and may be presented with new business opportunities, without any obligation to offer us the opportunity to purchase or construct such assets or to engage in such business opportunities.

Pursuant to the terms of our Partnership Agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our General Partner, its officers and directors or any of its affiliates, including Summit Investments and our Sponsor and its respective executive officers, directors and principals. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our General Partner and result in less than favorable treatment of us and our unitholders.

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The amount of cash we have available for distribution to holders of our units depends primarily on our cash flows rather than on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flows and not solely on profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we report net losses for GAAP purposes and may not make cash distributions during periods when we report net income for GAAP purposes.

The market price of our common units may fluctuate significantly and, due to limited daily trading volumes, an investor could lose all or part of its investment in us.

An investor may not be able to resell its common units at or above its acquisition price. Additionally, limited liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of the common units and limit the number of investors who are able to buy the common units.

The market price of our common units may decline and be influenced by many factors, some of which are beyond our control, including among others:

 

our quarterly distributions;

 

our quarterly or annual earnings or those of other companies in our industry;

 

the loss of a large customer;

 

announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics;

 

announcements by our competitors of significant contracts or acquisitions;

 

changes in accounting standards, policies, guidance, interpretations or principles;

 

general economic and geopolitical conditions;

 

the failure of securities analysts to cover our common units or changes in financial estimates by analysts; and

 

other factors described in these Risk Factors.

Our Sponsor may sell units in the public markets, which could reduce the market price of our outstanding common units.

Of the 93,493,473 common units outstanding at December 31, 2019, Summit Investments beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. If these entities were to dispose of a substantial portion of these units in the public market, whether in a single transaction or a series of transactions, it could reduce the market price of our common units. In addition, these sales, or the possibility that these sales may occur, could make it more difficult for us to sell our common units in the future.

Our Sponsor has rights to require underwritten offerings that could limit our ability to raise capital in the public equity market.

Our Sponsor and any other unitholders that have registration rights may require us to conduct underwritten offerings of our common units. If we want to access the capital markets (debt and equity), those unitholders’ ability to sell a portion of their common units could satisfy investors’ demand for our common units, reduce the market price for our common units, or interfere with our financing plans, and thereby could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

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If we fail to develop or maintain an effective system of internal controls, we may not be able to report our financial results timely and accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

As a publicly traded partnership, we are subject to the public reporting requirements of the Exchange Act, including the rules thereunder that will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable and timely financial reports, prevent fraud and to operate successfully as a publicly traded partnership. We prepare our consolidated financial statements in accordance with GAAP. Our efforts to develop and maintain our internal controls may not be successful and we may be unable to maintain effective controls over our financial processes and reporting in the future or to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, in addition to our limited accounting personnel and management resources, we can provide no assurance as to our or our independent registered public accounting firm's future conclusions about the effectiveness of our internal controls, and we may incur significant costs in our efforts to comply with Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to implement and maintain effective internal controls over financial reporting could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

Our Partnership Agreement replaces our General Partner's fiduciary duties to unitholders with contractual standards governing its duties.

Our Partnership Agreement contains provisions that eliminate fiduciary duties to which our General Partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our Partnership Agreement permits our General Partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our General Partner or otherwise, free of any duties to us and our unitholders, other than the implied contractual covenant of good faith and fair dealing. This entitles our General Partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our General Partner may make in its individual capacity include, among others:

 

how to allocate corporate opportunities among us and its affiliates;

 

whether to exercise its limited call right;

 

whether to seek approval of the resolution of a conflict of interest by the Conflicts Committee;

 

how to exercise its voting rights with respect to the units it owns;

 

whether to exercise its registration rights;

 

whether to transfer any units it owns to a third party; and

 

whether or not to consent to any merger or consolidation of the partnership or amendment to the Partnership Agreement.

By purchasing a common unit, a common unitholder agrees to become bound by the provisions in the Partnership Agreement, including the provisions discussed above.

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Our Partnership Agreement limits the liabilities of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty.

Our Partnership Agreement contains provisions that limit the liability of our General Partner and the rights of our unitholders with respect to actions taken by our General Partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our Partnership Agreement provides that:

 

whenever our General Partner makes a determination or takes, or declines to take, any other action in its capacity as our General Partner, our General Partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

 

our General Partner will not have any liability to us or our unitholders for decisions made in its capacity as a General Partner so long as such decisions are made in good faith;

 

our General Partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our General Partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

 

our General Partner will not be in breach of its obligations under the Partnership Agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

 

i.

approved by the Conflicts Committee, although our General Partner is not obligated to seek such approval;

 

ii.

approved by the vote of a majority of the outstanding common units, excluding any common units owned by our General Partner and its affiliates;

 

iii.

on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

 

iv.

fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our General Partner or the Conflicts Committee must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the Conflicts Committee and the Board of Directors determines that the resolution or course of action taken with respect to the affiliate transaction or conflict of interest satisfies either of the standards set forth in the final two subclauses above, then it will be presumed that, in making its decision, the Board of Directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our General Partner intends to limit its liability regarding our obligations.

Our General Partner intends to limit its liability under contractual arrangements so that the counterparties to such arrangements have recourse only against our assets, and not against our General Partner or its assets. Our General Partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our General Partner. Our Partnership Agreement provides that any action taken by our General Partner to limit its liability is not a breach of our General Partner's fiduciary duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our General Partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our unitholders.

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Reimbursements due to our General Partner and its affiliates for expenses incurred on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our General Partner.

Prior to making any distribution on our common units, we will reimburse our General Partner and its affiliates, including Summit Investments, for expenses they incur and payments they make on our behalf. Under our Partnership Agreement, we will reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who provide services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses to our General Partner and its affiliates will reduce the amount of available cash to pay cash distributions to our unitholders.

The New York Stock Exchange does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

We have listed our common units on the New York Stock Exchange. Because we are a publicly traded partnership, the New York Stock Exchange does not require us to have, and we do not have, a majority of independent directors on our General Partner's Board of Directors or a nominating and corporate governance committee. Additionally, any future issuance of additional common units or other securities, including to affiliates, will not be subject to the New York Stock Exchange's shareholder approval rules. Accordingly, unitholders do not have the same protections afforded to certain corporations that are subject to all of the New York Stock Exchange corporate governance requirements.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors.

Unlike the holders of common stock in a corporation, holders of our common units have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders have no right on an annual or ongoing basis to elect our General Partner or its Board of Directors. The Board of Directors has been chosen by Summit Investments. Furthermore, if our unitholders are dissatisfied with the performance of our General Partner, they have little ability to remove our General Partner. As a result of these limitations, the price at which the common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our Partnership Agreement also contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders' ability to influence the manner or direction of management.

Even if holders of our common units are dissatisfied, they may not be able to remove our General Partner without its consent.

The vote of the holders of at least 66 2/3% of all outstanding limited partner units voting together as a single class is required to remove our General Partner. As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units, representing a voting block sufficient to prevent the other limited partners from removing our General Partner.

Our Partnership Agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders' voting rights are further restricted by a provision of our Partnership Agreement providing that any person or group that owns 20% or more of any class of units then outstanding cannot vote on any matter, other than our General Partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the Board of Directors.

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We may issue additional units without unitholder approval, which would dilute existing ownership interests.

Except in the case of the issuance of units that rank equal to or senior to the Series A Preferred Units, our Partnership Agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to the common units that we may issue at any time without the approval of our unitholders.

We may issue additional Series A Preferred Units and any securities in parity with the Series A Preferred Units without any vote of the holders of the Series A Preferred Units (except where the cumulative distributions on the Series A Preferred Units or any parity securities are in arrears and in certain other circumstances) and without the approval of our common unitholders.

The issuance by us of additional common units or other equity securities of equal or senior rank will decrease our existing unitholders' proportionate ownership interest in us. In addition, the issuance by us of additional common units or other equity securities of equal or senior rank may have the following effects:

 

decreasing the amount of cash available for distribution on each unit;

 

increasing the ratio of taxable income to distributions;

 

diminishing the relative voting strength of each previously outstanding unit; and

 

causing the market price of the common units to decline.

Future issuances and sales of parity securities, or the perception that such issuances and sales could occur, may cause prevailing market prices for our common units and the Series A Preferred Units to decline and may adversely affect our ability to raise additional capital in the financial markets at times and prices favorable to us.

Furthermore, the payment of distributions on any additional units may increase the risk that we will not be able to make distributions at our prior per unit distribution levels. To the extent new units are senior to our common units, including units issued to third parties at a subsidiary level, their issuance will increase the uncertainty of the payment of distributions on our common units.

Holders of Series A Preferred Units have limited voting rights, which may be diluted.

Although holders of the Series A Preferred Units are entitled to limited voting rights with respect to certain matters, the Series A Preferred Units generally vote separately as a class along with any other series of our parity securities that we may issue upon which like voting rights have been conferred and are exercisable. As a result, the voting rights of holders of Series A Preferred Units may be significantly diluted, and the holders of such other series of parity securities that we may issue may be able to control or significantly influence the outcome of any vote.

Summit Investments or our Sponsor may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. The sale of any of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Our General Partner has a limited call right that may require an investor to sell its units at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of our outstanding common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our Partnership Agreement. As a result, an investor may be required to sell its common units at an undesirable time or price and may not receive any return on its investment. An investor may also incur a tax liability upon a sale of its units.

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As of December 31, 2019, Summit Investments beneficially owned 45,318,866 common units out of 93,493,473 outstanding common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. As such, our General Partner and its affiliates controlled a total of 51,234,693 common units, or 54.8% of our common units outstanding as of December 31, 2019.

An investor's liability may not be limited if a court finds that unitholder action constitutes control of our business.

A General Partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the General Partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. An investor could be liable for any and all of our obligations as if it was a General Partner if a court or government agency were to determine that:

 

we were conducting business in a state but had not complied with that particular state's partnership statute; or

 

an investor's right to act with other unitholders to remove or replace our General Partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute control of our business.

Our Partnership Agreement designates the Court of Chancery of the State of Delaware as the exclusive forum for certain types of actions and proceedings that may be initiated by our unitholders, which limits our unitholders’ ability to choose the judicial forum for disputes with us or our General Partner’s directors, officers or other employees.

Our Partnership Agreement provides that, with certain limited exceptions, the Court of Chancery of the State of Delaware is the exclusive forum for any claims, suits, actions or proceedings (1) arising out of or relating in any way to our Partnership Agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of our Partnership Agreement or the duties, obligations or liabilities among our partners, or obligations or liabilities of our partners to us, or the rights or powers of, or restrictions on, our partners or us), (2) brought in a derivative manner on our behalf, (3) asserting a claim of breach of a duty (including a fiduciary duty) owed by any of our, or our General Partner’s, directors, officers, or other employees, or owed by our General Partner, to us or our partners, (4) asserting a claim against us arising pursuant to any provision of the Delaware Revised Uniform Limited Partnership Act or (5) asserting a claim against us governed by the internal affairs doctrine. Any person or entity purchasing or otherwise acquiring any interest in our common units is deemed to have received notice of and consented to the foregoing provisions. This exclusive forum provision does not apply to a cause of action brought under federal or state securities laws. Although management believes this choice of forum provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against us and our General Partner’s directors and officers. The enforceability of similar choice of forum provisions in other companies’ certificates of incorporation or similar governing documents has been challenged in legal proceedings and it is possible that in connection with any action a court could find the choice of forum provisions contained in our Partnership Agreement to be inapplicable or unenforceable in such action. If a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect our financial position, results of operations and ability to make cash distributions to our unitholders.

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Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the Partnership Agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

If an investor is not an eligible holder, it may not receive distributions or allocations of income or loss on those common units and those common units will be subject to redemption.

We have adopted certain requirements regarding those investors who may own our common units and Series A Preferred Units. Eligible holders are U.S. individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity's owners are U.S. individuals or entities subject to such taxation. If an investor is not an eligible holder, our General Partner may elect not to make distributions or allocate income or loss on that investor's units, and it runs the risk of having its units redeemed by us at the lower of purchase price cost or the then-current market price. The redemption price may be paid in cash or by delivery of a promissory note, as determined by our General Partner.

Our Series A Preferred Units have rights, preferences and privileges that are not held by, and are preferential to the rights of, holders of our common units.

Our Series A Preferred Units rank senior to our common units with respect to distribution rights and rights upon liquidation. These preferences could adversely affect the market price for our common units, or could make it more difficult for us to sell our common units in the future. In addition, our Subsidiary Series A Preferred Units have priority over the common unitholders with respect to the cash flow from Permian Holdco.

In addition, (i) prior to December 15, 2022, distributions on the Series A Preferred Units accrue and are cumulative at the rate of 9.50% per annum of $1,000, the liquidation preference of the Series A Preferred Units and (ii) on and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of $1,000 equal to the three-month LIBOR plus a spread of 7.43%.

The distribution rate of the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service.

Our obligation to pay distributions on our Series A Preferred Units and Permian Holdco’s obligation to pay the distributions on the Subsidiary Series A Preferred Units could impact our liquidity and reduce the amount of cash flow available for working capital, capital expenditures, growth opportunities, acquisitions, and other general partnership purposes. Our obligations to the holders of the Series A Preferred Units and Permian Holdco’s obligations to the holders of the Subsidiary Series A Preferred Units could also limit our ability to obtain additional financing or increase our borrowing costs, which could have an adverse effect on our financial condition.

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Our Series A Preferred Units contain covenants that may limit our business flexibility.

Our Series A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of 66 2⁄3% of the Series A Preferred Units. The need to obtain the approval of holders of the Series A Preferred Units before taking these actions could impede our ability to take certain actions that management or the Board of Directors may consider to be in the best interests of our unitholders. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units, voting as a single class, is necessary to amend the Partnership Agreement in any manner that would have a material adverse effect on the existing preferences, rights, powers, duties or obligations of the Series A Preferred Units. The affirmative vote of 66 2⁄3% of the outstanding Series A Preferred Units and any outstanding series of other preferred units, voting as a single class, is necessary to (A) under certain circumstances, create or issue certain equity securities that are senior to our common units or (B) declare or pay any distribution to common unitholders out of capital surplus.

Tax Risks

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, then our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently 21%, and would likely pay state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions, or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes, there would be material reductions in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units. This could adversely affect our financial position, results of operations and ability to make distributions to our unitholders.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations of applicable law, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships.

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Any modification to the U.S. federal income tax laws and interpretations could make it more difficult or impossible to meet the exception for us to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such changes will ultimately be enacted, but it is possible that a change in law could affect us and may, if enacted, be applied retroactively. Any such changes could negatively impact the value of an investment in our units.

Our unitholders are required to pay income taxes on their share of our taxable income even if they do not receive any cash distributions from us. A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, transactions in which we engage or changes in law and may be substantially different from any estimate we make in connection with a unit offering.

A unitholder’s allocable share of our taxable income will be taxable to it, which may require the unitholder to pay federal income taxes and, in some cases, state and local income taxes, even if the unitholder receives cash distributions from us that are less than the actual tax liability that results from that income or no cash distributions at all.

A unitholder’s share of our taxable income, and its relationship to any distributions we make, may be affected by a variety of factors, including our economic performance, which may be affected by numerous business, economic, regulatory, legislative, competitive and political uncertainties beyond our control, and certain transactions in which we might engage. For example, we may engage in transactions that produce substantial taxable income allocations to some or all of our unitholders without a corresponding increase in cash distributions to our unitholders, such as a sale or exchange of assets, the proceeds of which are reinvested in our business or used to reduce our debt, or an actual or deemed satisfaction of our indebtedness for an amount less than the adjusted issue price of the debt. A unitholder’s ratio of its share of taxable income to the cash received by it may also be affected by changes in law. For instance, under the tax reform law known as the Tax Cuts and Jobs Act (the “Tax Reform Legislation”), the net interest expense deductions of certain business entities, including us, are limited to 30% of such entity’s “adjusted taxable income,” which is generally taxable income with certain modifications. If the limit applies, a unitholder’s taxable income allocations will be more (or its net loss allocations will be less) than would have been the case absent the limitation.

From time to time, in connection with an offering of our common units, we may state an estimate of the ratio of federal taxable income to cash distributions that a purchaser of common units in that offering may receive in a given period. These estimates depend in part on factors that are unique to the offering with respect to which the estimate is stated, so the expected ratio applicable to other common units will be different, and in many cases less favorable, than these estimates. Moreover, even in the case of common units purchased in the offering to which the estimate relates, the estimate may be incorrect, due to the uncertainties described above, challenges by the IRS to tax reporting positions which we adopt, or other factors. The actual ratio of taxable income to cash distributions could be higher or lower than expected, and any differences could be material and could materially affect the value of the common units.

If the IRS contests the federal income tax positions we take, the market for our units may be adversely impacted and the cost of any IRS contest would likely reduce our cash available for distribution to our unitholders.

The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse effect on the market for our units and the price at which they trade. In addition, our costs of any contest with the IRS would be borne indirectly by our unitholders because the costs would likely reduce our cash available for distribution.

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Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Reform Legislation, our deduction for “business interest,” (including, under proposed Treasury Regulations, our deduction for distributions on our Series A Preferred Units) is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years, beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Tax gain or loss on the disposition of our units could be more or less than expected.

If a unitholder sells its units, a gain or loss will be recognized for federal income tax purposes equal to the difference between the amount realized and the unitholder's tax basis in those units. Because distributions in excess of a unitholder's allocable share of its net taxable income decrease its tax basis in its units, the amount, if any, of such prior excess distributions with respect to the units it sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price it receives is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of a unitholder's units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if a unitholder sells its units, it may incur a tax liability in excess of the amount of cash it receives from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our units that may result in adverse tax consequences to them.

Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to an organization that is exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income (“UBTI”) and will be taxable to the exempt organization as UBTI on the exempt organization’s tax return in the year the exempt organization is allocated the income. Under the Tax Reform Legislation, an exempt organization is required to independently compute its UBTI from each separate unrelated trade or business which may prevent an exempt organization from utilizing losses we allocate to the organization against the organization’s UBTI from other sources and vice versa. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.

Under the Tax Reform Legislation, if a unitholder sells or otherwise disposes of a unit, the transferee is required to withhold 10.0% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferee but were not withheld. However, the U.S. Treasury Department and the IRS suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, until regulations or other guidance has been issued. In May 2019, the IRS issued proposed Treasury Regulations that would require withholding on open market transactions, effective 60 days after the issuance of final Treasury Regulations, but in the case of a transfer made through a broker, would exclude a partner’s share of liabilities from the amount realized. In addition, the obligation to withhold would be imposed on the broker instead of the transferee. It is not clear if or when the proposed Treasury Regulations will be finalized and in what form, or if other guidance will be issued.

Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our units.

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We treat each holder of our common units as having the same tax benefits without regard to the actual common units held. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. A successful IRS challenge also could affect the timing of these tax benefits or the amount of gain from a unitholder’s sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the unitholder’s tax returns.

Treatment of distributions on our Series A Preferred Units as guaranteed payments for the use of capital creates a different tax treatment for the holders of our Series A Preferred Units than the holders of our common units and such distributions are not eligible for the 20% deduction for qualified publicly traded partnership income.

The tax treatment of distributions on our Series A Preferred Units is uncertain. We will treat the holders of Series A Preferred Units as partners for tax purposes and will treat distributions on the Series A Preferred Units as guaranteed payments for the use of capital that will generally be taxable to the holders of Series A Preferred Units as ordinary income. Although a holder of Series A Preferred Units could recognize taxable income from the accrual of such a guaranteed payment even in the absence of a contemporaneous distribution, we anticipate accruing and making the guaranteed payment distributions semi-annually on the 15th day of June and December through December 15, 2022, and quarterly on the 15th day of March, June, September and December thereafter. Because the guaranteed payment for each unit must accrue as income to a holder during the taxable year of the accrual, the guaranteed payment attributable to the period beginning December 15th and ending December 31st will accrue to the holder of record of a Series A Preferred Unit on December 31st for such period. Otherwise, except in the case of our liquidation, the holders of Series A Preferred Units are generally not anticipated to share in our items of income, gain, loss or deduction. We will not allocate any share of its nonrecourse liabilities to the holders of Series A Preferred Units.

Treasury Regulations, provide that a guaranteed payment for the use of capital generally is not taken into account for purposes of computing qualified business income for purposes of the 20% deduction for qualified publicly traded partnership will not constitute an allocable or distributive share of such income. As a result, the guaranteed payment for use of capital received by holders of our Series A Preferred Units may not be eligible for the 20% deduction for qualified publicly traded partnership income.

A holder of Series A Preferred Units will be required to recognize gain or loss on a sale of units equal to the difference between the holder’s amount realized and tax basis in the units sold. The amount realized generally will equal the sum of the cash and the fair market value of other property such holder receives in exchange for such Series A Preferred Units. Subject to general rules requiring a blended basis among multiple partnership interests, the tax basis of a Series A Preferred Unit will generally be equal to the sum of the cash and the fair market value of other property paid by the holder to acquire such Series A Preferred Unit. Gain or loss recognized by a holder on the sale or exchange of a Series A Preferred Unit held for more than one year generally will be taxable as long-term capital gain or loss. Because holders of Series A Preferred Units will not generally be allocated a share of our items of depreciation, depletion or amortization, it is not anticipated that such holders would be required to recharacterize any portion of their gain as ordinary income as a result of the recapture rules.

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Investment in the Series A Preferred Units by tax-exempt investors, such as employee benefit plans and individual retirement accounts, and non-U.S. persons raises issues unique to them. Although the issue is not free from doubt, we will treat distributions to non-U.S. holders of the Series A Preferred Units as “effectively connected income” (which will subject holders to U.S. net income taxation and possibly the branch profits tax) that are subject to withholding taxes imposed at the highest effective tax rate applicable to such non-U.S. holders. If the amount of withholding exceeds the amount of U.S. federal income tax actually due, non-U.S. holders may be required to file U.S. federal income tax returns in order to seek a refund of such excess. The treatment of guaranteed payments for the use of capital to tax-exempt investors is not certain and such payments may be treated as unrelated business taxable income for federal income tax purposes.  

All holders of our Series A Preferred Units are urged to consult a tax advisor with respect to the consequences of owning our Series A Preferred Units.

We prorate our items of income, gain, loss and deduction for U.S, federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. Treasury Regulations allow a similar monthly simplifying convention, but do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method, or if new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their units.

We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift of income, gain, loss and deduction among our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we make many fair market value estimates using a methodology based on the market value of our units as a means to measure the fair market value of our assets. The IRS may challenge these valuation methods and the resulting allocations of income, gain, loss and deduction.

A successful IRS challenge to these methods or allocations could adversely affect the amount, character and timing of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders' sale of units and could have a negative impact on the value of the units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.

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If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, the IRS (and some states) may collect any resulting taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (and will choose to do so) under all circumstances, or that we will be able to (or choose to) effect corresponding shifts in state income or similar tax liability resulting from the IRS adjustment in states in which we do business in the year under audit or in the adjustment year. If, we make payments of taxes, penalties and interest resulting from audit adjustments, we may require our unitholders and former unitholders to reimburse us for such taxes (including any applicable penalties or interest) or, if we are required to bear such payment, our cash available for distribution to our unitholders could be substantially reduced. Additionally, we may be required to allocate an adjustment disproportionately among our unitholders, causing the publicly traded units to have different capital accounts, unless the IRS issues further guidance.  

In the event the IRS makes an audit adjustment to our income tax returns and we do not or cannot shift the liability to our unitholders in accordance with their interests in us during the year under audit, we will generally have the ability to request that the IRS reduce the determined underpayment by reducing the suspended passive loss carryovers of our unitholders (without any compensation from us to such unitholders), to the extent such underpayment is attributable to a net decrease in passive activity losses allocable to certain partners. Such reduction, if approved by the IRS, will be binding on any affected unitholders.

As a result of investing in our units, our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if the unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. Some of the states in which we conduct business currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is the unitholder's responsibility to file all federal, state and local tax returns.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax laws and regulations, including federal and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted that could result in increased tax expenditures in the future. Many of these tax liabilities are subject to audits by the respective taxing authority. These audits may result in additional taxes as well as interest and penalties.

Item 1B. Unresolved Staff Comments.

Not applicable.

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Item 2. Properties.

Our gathering systems, the unconventional resource basins in which they operate, and the reportable segments in which they are reported are as follows:  

 

Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio, is included in the Utica Shale reportable segment;

 

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, is included in the Williston Basin reportable segment;

 

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, is included in the Williston Basin reportable segment;

 

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, is included in the DJ Basin reportable segment;

 

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, is included in the Permian Basin reportable segment;

 

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, is included in the Piceance Basin reportable segment;

 

DFW Midstream, a natural gas gathering system operating in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas, is included in the Barnett Shale reportable segment; and  

 

Mountaineer Midstream, a natural gas gathering system operating in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia, is included in the Marcellus Shale reportable segment.  

For additional information on our midstream assets and their capacities, see Item 1. Business.

Our real property falls into two categories: (i) parcels that we own in fee and (ii) parcels in which our interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities, permitting the use of such land for our operations. Portions of the land on which our gathering systems and other major facilities are located are owned by us in fee title, and we believe that we have valid title to these lands. The remainder of the land on which our major facilities are located are held by us pursuant to long-term leases or easements between us and the underlying fee owner, or permits with governmental authorities. We believe that we have valid leasehold estates or fee ownership in such lands or valid permits with governmental authorities. We have no knowledge of any material challenge to the underlying fee title of any material lease, easement, right-of-way, permit or license held by us or to our title to any material lease, easement, right-of-way, permit or license. We believe that we have satisfactory title to all of our material leases, easements, rights-of-way, permits and licenses with the exception of certain ordinary course encumbrances and permits with governmental entities that have been applied for, but not yet issued.

In addition, we lease various office space under leases to support our operations. On March 2, 2020, we relocated our corporate headquarters to Houston, Texas from the Woodlands, Texas.

 

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Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any significant legal or governmental proceedings, except as noted below. In addition, we are not aware of any significant legal or governmental proceeding contemplated to be brought against us, under the various environmental protection statutes to which we are subject, except as noted below.

The U.S. Department of Justice has issued grand jury subpoenas to Summit Investments, the Partnership, our General Partner and Meadowlark Midstream requesting certain materials related to an incident involving a produced water disposal pipeline owned by Meadowlark Midstream that resulted in a discharge of materials into the environment. On June 19, 2015, Meadowlark Midstream and Summit Investments received a complaint from the North Dakota Industrial Commission seeking approximately $2.5 million in fines and other fees related to the rupture. On March 3, 2016, the Partnership agreed to acquire, among other things, substantially all of the issued and outstanding membership interests of Meadowlark Midstream from an indirect, wholly owned subsidiary of Summit Investments in connection with the 2016 Drop Down. The Contribution Agreement executed in connection with the 2016 Drop Down contains customary representations and warranties, and Summit Investments has agreed to indemnify the Partnership with respect to certain losses, including losses associated with the above described incident. While we cannot predict the ultimate outcome of this matter with certainty, we believe at this time that it is not likely that the Partnership or our General Partner will be subject to any material liability as a result of any governmental proceeding related to the incident.

On October 18, 2019, a petition was filed in the District Court of Tarrant County, Texas by Sage Natural Resources, LLC (the “plaintiff”) against us and certain of our affiliates. The plaintiff is a party to a gathering agreement and a gas marketing agreement with DFW Midstream. In its petition, the plaintiff alleges various claims relating to fees owed pursuant to the terms of these agreements, including breach of contract, fraud, fraudulent inducement, tortious interference, and negligent misrepresentation, as well as certain discriminatory rate claims under Texas law. The plaintiff is disputing its multi-year MVC shortfall payment in the amount of approximately $7.3 million that came due in the fourth quarter of 2019 and seeks a rescission of the gas marketing agreement and the gas gathering agreement, as well as actual and exemplary damages and attorney’s fees. While we cannot predict the ultimate outcome of this matter with certainty, we do not believe that it is likely that we or our affiliates will be subject to any material liability as a result of this matter and are defending ourselves vigorously against the plaintiff’s claims. In addition, we are actively pursuing collection of the multi-year MVC shortfall payment from both the plaintiff and its parent, which guaranteed Sage's performance.

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our limited partner common units, ticker symbol "SMLP," trade on the NYSE. As of February 14, 2020, there were approximately 10,744 common unitholders, including beneficial owners of common units held in street name.

On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit for the quarterly period ended December 31, 2019. The distribution, which totaled $11.7 million, was paid on February 14, 2020, to unitholders of record at the close of business on February 7, 2020.

Our Cash Distribution Policy and Restrictions on Distributions

General

Our Cash Distribution Policy.  Our Partnership Agreement requires us to distribute all of our available cash quarterly, subject to reserves established by our General Partner. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we have more cash to distribute to our unitholders than would be the case were we subject to federal income tax.

We pay our distributions on or about the 15th of each of February, May, August and November to holders of record on or about seven days prior to such distribution date. We make the distribution on the business day immediately preceding the indicated distribution date if the distribution date falls on a holiday or non-business day.

Pursuant to the Equity Restructuring Agreement, our general partner interest was converted into a non-economic general partner interest. For additional information, see Note 12 to the consolidated financial statements.

Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy.  There is no guarantee that our unitholders will receive quarterly distributions from us. We do not have a legal obligation to pay any distribution except to the extent we have available cash as defined in our Partnership Agreement. Our cash distribution policy may be changed at any time and is subject to certain restrictions, including the following:

 

Our cash distribution policy is subject to restrictions on distributions under our Revolving Credit Facility. Our Revolving Credit Facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.

 

Our cash distribution policy is subject to restrictions on distributions under our Series A Preferred Units. Our Series A Preferred Units contain covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.  

 

Our General Partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to our unitholders from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our General Partner in good faith will be binding on our unitholders.

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Although our Partnership Agreement requires us to distribute all of our available cash, our Partnership Agreement, including the provisions requiring us to distribute all of our available cash, may be amended. We can amend our Partnership Agreement with the consent of our General Partner and the approval of a majority of the outstanding common units (including common units beneficially owned by Summit Investments). As of December 31, 2019, Summit Investments, which is the ultimate owner of our General Partner, beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners owned 5,915,827 common units.

 

Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.

 

Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

 

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.  

 

If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures.

Preferred Unit Distributions

Series A Preferred Units

In November 2017, we issued 300,000 Series A 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.

Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose.

The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%. See Note 12 to the consolidated financial statements for additional details.

Subsidiary Series A Preferred Units

In December 2019, Permian Holdco issued 30,000 Subsidiary Series A Preferred Units representing limited partner interests in Permian Holdco at a price of $1,000 per unit. Permian Holdco used the net proceeds of $27.4 million (after deducting offering expenses) to fund capital calls associated with the Double E Project.

Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable quarterly in arrears 21 days after the quarter ending March, June, September and December of each year (each, a “Subsidiary Series A Preferred Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Subsidiary Series A Preferred Distribution Payment Date, in each case, when, as, and if declared by the board of directors of Permian Holdco out of legally available funds for such purpose.

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The distribution rate is 7.00% per annum of the $1,000 issue amount per outstanding Permian Holdco Subsidiary Series A Preferred Unit. Permian Holdco has the option to pay this distribution in-kind until the earlier of June 30, 2022 or the first full quarter following the date the Double E pipeline is placed in service. See Note 12 to the consolidated financial statements for additional details.

Stock Performance Table

The following graph compares the cumulative total unitholder return on our common units to the cumulative total return of the S&P 500 Stock Index and the Alerian MLP Index for the five years ended December 31, 2019 by assuming $100 was invested in each investment option as of December 31, 2014. The Alerian MLP Index is the leading gauge of energy master limited partnerships, or MLPs, and is calculated using a float-adjusted, capitalization-weighted methodology.

 

Issuer Purchases of Equity Securities

We made no repurchases of our common units during the quarter or year ended December 31, 2019.

Sponsor Purchases of Equity Securities

Our Sponsor made no repurchases of our common units during the quarter or year ended December 31, 2019.

Equity Compensation Plans

The information relating to SMLP’s equity compensation plans required by Item 5 is included in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

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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 consolidated financial statements of SMLP.

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

 

$

2,573,451

 

 

$

3,020,562

 

 

$

2,894,793

 

 

$

3,115,179

 

 

$

3,164,672

 

Total long-term debt

 

 

1,470,299

 

 

 

1,257,731

 

 

 

1,051,192

 

 

 

1,240,301

 

 

 

1,267,270

 

Deferred Purchase Price Obligation

 

 

178,453

 

 

 

383,934

 

 

 

362,959

 

 

 

563,281

 

 

 

 

Mezzanine capital

 

 

27,450

 

 

 

 

 

 

 

 

 

 

 

 

 

Partners' capital

 

 

763,516

 

 

 

1,221,224

 

 

 

1,389,669

 

 

 

1,169,673

 

 

 

1,747,299

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Market price per common unit

 

$

3.01

 

 

$

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

 

 

$

400,557

 

Total costs and expenses (1)

 

 

402,340

 

 

 

371,702

 

 

 

510,577

 

 

 

290,582

 

 

 

557,735

 

Interest expense

 

 

74,429

 

 

 

60,535

 

 

 

68,131

 

 

 

63,810

 

 

 

59,092

 

Early extinguishment of debt

 

 

 

 

 

 

 

 

22,039

 

 

 

 

 

 

 

Deferred Purchase Price Obligation

 

 

(1,982

)

 

 

20,975

 

 

 

(200,322

)

 

 

55,854

 

 

 

 

Loss from equity method investees (2)

 

 

(337,851

)

 

 

(10,888

)

 

 

(2,223

)

 

 

(30,344

)

 

 

(6,563

)

Net (loss) income

 

 

(369,833

)

 

 

42,351

 

 

 

86,050

 

 

 

(38,187

)

 

 

(222,228

)

(Loss) earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common unit - basic

 

$

(4.84

)

 

$

0.06

 

 

$

0.99

 

 

$

(0.71

)

 

$

(3.20

)

Common unit - diluted

 

 

(4.84

)

 

 

0.06

 

 

 

0.98

 

 

 

(0.71

)

 

 

(3.20

)

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

 

 

$

142,719

 

 

$

272,225

 

Contributions to equity method investees

 

 

 

 

 

4,924

 

 

 

25,513

 

 

 

31,582

 

 

 

86,200

 

Investment in equity method investee

 

 

18,316

 

 

 

 

 

 

 

 

 

 

 

 

 

Acquisition capital expenditures (4)

 

 

 

 

 

 

 

 

 

 

 

866,858

 

 

 

288,618

 

Purchase of noncontrolling interest

 

 

 

 

 

10,981

 

 

 

797

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Other financial data:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions declared per unit (5)

 

$

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.

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(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) Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs (see Notes 12 and 17 to the consolidated financial statements).

(5) Represents distributions declared in a given period. 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.

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Item 7. 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. The discussion of our financial condition and results of operations for the year ended December 31, 2017 included in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2018 is incorporated by reference into this MD&A.

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.

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;

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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.

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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

 

$

(369,833

)

 

$

42,351

 

 

$

86,050

 

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

 

$

182,337

 

 

$

227,929

 

 

$

237,832

 

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 common unitholders

 

$

116,624

 

 

$

180,705

 

 

$

179,103

 

Distributions to Series A Preferred unitholders

 

 

28,500

 

 

 

28,500

 

 

 

2,375

 

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

)

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.

 

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.

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On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion. The terms of the Second Amendment were approved by the Conflicts Committee, which consists entirely of independent directors.

Previously, in February 2019, we and SMP Holdings signed a first amendment to the Contribution Agreement related to the 2016 Drop Down pursuant to which, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation. Following the payment, the Remaining Consideration was fixed at $303.5 million, with such amount being payable by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration was required to be paid on or before June 30, 2020 and interest would accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The first amendment was superseded by the second amendment.

 

On March 22, 2019, pursuant to an equity restructuring agreement with the General Partner and SMP Holdings, we cancelled our IDRs and converted our 2% economic GP interest into a non-economic GP interest in exchange for 8,750,000 SMLP common units, which were issued to SMP Holdings in the Equity Restructuring. As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. ECP continues to control the non-economic GP interest in SMLP.

 

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.

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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.

 

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:

 

In 2018, the present value of the Deferred Purchase Price Obligation increased by $21.0 million. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period (see Note 17 to the consolidated financial statements).

 

Increased natural gas, NGLs and condensate sales and cost of natural gas and NGLs associated with increased marketing related activities.

 

In November 2018, a subsidiary of SMLP purchased the remaining 1% ownership interest in OpCo held by a subsidiary of Summit Investments for approximately $10.9 million.

 

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.

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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 2017, we updated the Deferred Purchase Price Obligation based on management’s estimate of forecasted Business Adjusted EBITDA and capital expenditures for the 2016 Drop Down Assets. The decrease was primarily attributable to lower expected Business Adjusted EBITDA in 2018 and 2019 associated with the 2016 Drop Down Assets partially offset by lower estimated capital expenditures. The revision in estimated Business Adjusted EBITDA and estimated capital expenditures reflects a slower expected pace of drilling and completion activities from our customers, particularly in the Utica Shale in 2018 and 2019. The revised estimates had a favorable impact on our consolidated statements of operations for the year ended December 31, 2017.

 

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.

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.

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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 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.

 

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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.

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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.

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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 and our Senior Notes as well as amortization expense associated with debt issuance costs.

Deferred Purchase Price Obligation.  Represents the change in fair value associated with the Deferred Purchase Price Obligation.

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.

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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

 

 

97,587

 

 

 

96,878

 

 

 

93,882

 

 

1%

 

3%

General and administrative

 

 

54,139

 

 

 

52,877

 

 

 

54,681

 

 

2%

 

(3%)

Depreciation and amortization

 

 

110,206

 

 

 

107,100

 

 

 

115,475

 

 

3%

 

(7%)

Transaction costs

 

 

1,788

 

 

 

 

 

 

73

 

 

*

 

*

(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

 

 

402,340

 

 

 

371,702

 

 

 

510,577

 

 

8%

 

(27%)

Other income (expense)

 

 

451

 

 

 

(169

)

 

 

298

 

 

*

 

*

Interest expense

 

 

(74,429

)

 

 

(60,535

)

 

 

(68,131

)

 

23%

 

(11%)

Early extinguishment of debt

 

 

 

 

 

 

 

 

(22,039

)

 

*

 

*

Deferred Purchase Price Obligation

 

 

1,982

 

 

 

(20,975

)

 

 

200,322

 

 

*

 

*

(Loss) income before income taxes and

    loss from equity method investees

 

 

(30,808

)

 

 

53,272

 

 

 

88,614

 

 

*

 

*

Income tax expense

 

 

(1,174

)

 

 

(33

)

 

 

(341

)

 

*

 

*

Loss from equity method investees

 

 

(337,851

)

 

 

(10,888

)

 

 

(2,223

)

 

*

 

390%

Net (loss) income

 

$

(369,833

)

 

$

42,351

 

 

$

86,050

 

 

*

 

*

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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.

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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.

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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 $30.6 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.

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Total costs and expenses decreased $138.9 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 $3.0 million increase in operation and maintenance expense primarily due to planned compressor overhaul maintenance.

 

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 $8.4 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 increased $0.7 million for the year ended December 31, 2019 compared to the year ended December 31, 2018.

Operation and maintenance expense increased $3.0 million for the year ended December 31, 2018 compared to the year ended December 31, 2017, primarily due to an increase in planned compressor overhaul maintenance.

General and Administrative. General and administrative expense increased $1.3 million for the year ended December 31, 2019 compared to the year ended December 31, 2018, primarily due to a $7.3 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 $1.8 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.

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Transaction Costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $0.9 million in financial advisory costs associated with the Equity Restructuring and $0.5 million in financial advisory costs associated with the DPPO restructuring

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 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 and (iii) a lower average outstanding balance on the Revolving Credit Facility. 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.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the year ended December 31, 2019 represents the change in present value to Remaining Consideration in connection with the 2016 Drop Down (see Note 17 to the consolidated financial statements).

Deferred Purchase Price Obligation recognized during the year ended December 31, 2018 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period.

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.

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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.

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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.

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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.

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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%

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* Not considered meaningful

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

 

 

*

 

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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%)

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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.

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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.

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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.

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.

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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.

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.

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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, early extinguishment of debt and a change in the Deferred Purchase Price Obligation fair value.

 

 

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

 

 

48,989

 

 

 

47,070

 

 

 

47,507

 

 

4%

 

(1%)

Transaction costs

 

 

1,788

 

 

 

 

 

 

73

 

 

 

 

 

Interest expense

 

 

74,429

 

 

 

60,535

 

 

 

68,131

 

 

23%

 

(11%)

Early extinguishment of debt (1)

 

 

 

 

 

 

 

 

22,039

 

 

*

 

*

Deferred Purchase Price Obligation

 

 

(1,982

)

 

 

20,975

 

 

 

(200,322

)

 

*

 

*

 

* 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 $1.9 million compared to the year ended December 31, 2018, primarily due to a $7.3 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 compared to the year ended December 31, 2017, primarily reflecting reductions in information technology costs.

Transaction costs. Transaction costs recognized during the year ended December 31, 2019 primarily relate to $0.9 million in financial advisory costs associated with the Equity Restructuring and $0.5 million in financial advisory costs associated with the DPPO restructuring.

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Interest Expense. Interest expense increased $13.9 million compared to the year ended December 31, 2018 primarily as a result of a higher average outstanding balance on the Revolving Credit Facility.

Interest expense decreased $7.6 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 and (iii) a lower average outstanding balance on the Revolving Credit Facility. 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.

Deferred Purchase Price Obligation. Deferred Purchase Price Obligation recognized during the year ended December 31, 2019 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down (see Note 17 to the consolidated financial statements).

Deferred Purchase Price Obligation recognized during the year ended December 31, 2018 represents the change in present value of the estimated Remaining Consideration to be paid in connection with the 2016 Drop Down. The change was primarily due to the passage of time and an associated decrease in the discount rate, partially offset by the continued slowing and deferral of drilling and completion activities to periods outside of the DPPO measurement period.

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.  

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.

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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.

For additional information on our long-term debt, see Notes 10 and 18 to the consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Note 17 to the consolidated financial statements and the “Contractual Obligations Update” section below).

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.

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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

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Net cash provided by operating activities

 

$

182,337

 

 

$

227,929

 

 

$

237,832

 

Net cash used in investing activities

 

 

(90,870

)

 

 

(216,279

)

 

 

(148,683

)

Net cash used in financing activities

 

 

(63,472

)

 

 

(8,735

)

 

 

(95,147

)

Net change in cash, cash equivalents and restricted cash

 

$

27,995

 

 

$

2,915

 

 

$

(5,998

)

The components of the net change in cash, cash equivalents and restricted cash were as follows:

Operating activities.  Cash flows from operating activities for the year ended December 31, 2019, primarily reflected:

 

a $12.2 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 $6.8 million decrease in cash interest payments 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;

 

a $10.9 million purchase of a noncontrolling interest; 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:

 

$145.1 million of distributions;

 

$211.0 million of net borrowings under our Revolving Credit Facility;

 

$151.8 million payment on the Deferred Purchase Price Obligation; and

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$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:

 

$209.2 million of distributions; and

 

$205.0 million of net borrowings under our Revolving Credit Facility.

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)

 

$

1,757,558

 

 

$

78,884

 

 

$

1,106,799

 

 

$

57,500

 

 

$

514,375

 

Deferred Purchase Price Obligation (2)

 

 

180,750

 

 

 

 

 

 

180,750

 

 

 

 

 

 

 

Purchase obligations (3)

 

 

132,622

 

 

 

132,622

 

 

 

 

 

 

 

 

 

 

Finance leases (4)

 

 

1,991

 

 

 

1,299

 

 

 

692

 

 

 

 

 

 

 

Operating leases (4)

 

 

4,803

 

 

 

1,705

 

 

 

1,555

 

 

 

648

 

 

 

895

 

Total contractual obligations

 

$

2,077,724

 

 

$

214,510

 

 

$

1,289,796

 

 

$

58,148

 

 

$

515,270

 

 

(1) For the purpose of calculating future interest on the Revolving Credit Facility, 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) See Note 17 to the consolidated financial statements.

(3) Represents agreements to purchase goods or services that are enforceable and legally binding.

(4) See Item 2. Properties and Note 16 to the consolidated financial statements.

In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. Pursuant to the Equity Restructuring, in April 2019, the Partnership made a cash payment of $100 million to SMP Holdings in partial settlement of the Deferred Purchase Price Obligation.

On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion.

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of December 31, 2019, the Remaining Consideration, which reflects the net present value of the $180.75 million Deferred Purchase Price Obligation, was $178.5 million on the consolidated balance sheet using a discount rate of 5.25%.

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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.

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.

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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 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.

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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.

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.

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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 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;

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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;

 

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 or the Deferred Purchase Price Obligation, 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.

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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Interest Rate Risk

Our current interest rate risk exposure is largely related to our debt portfolio. As of December 31, 2019, we had $800.0 million principal of fixed-rate Senior Notes and $677.0 million outstanding under our variable rate Revolving Credit Facility (see Note 10 to the consolidated financial statements). While existing fixed-rate debt mitigates the downside impact of fluctuations in interest rates, future issuances of long-term debt could be impacted by increases in interest rates, which could result in higher overall interest costs. In addition, the borrowings under our Revolving Credit Facility, which have a variable interest rate, also expose us to the risk of increasing interest rates. For the year ended December 31, 2019, a hypothetical 1% increase (decrease) in interest rates would have increased (decreased) our interest expense by approximately $5.7 million assuming no changes in amounts drawn or other variables under our Revolving Credit Facility or Senior Notes.

Commodity Price Risk

We currently generate a majority of our revenues pursuant to primarily long-term and fee-based gathering agreements, many of which include MVCs and areas of mutual interest. Our direct commodity price exposure relates to (i) the sale of physical natural gas and/or NGLs purchased under percentage-of-proceeds and 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. Our gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we sell to offset the power costs we incur to operate our electric-drive compression assets. Our gathering agreements with our Grand River customers permit us to retain condensate volumes from the Grand River system gathering lines. We manage our direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales. We do not enter into risk management contracts for speculative purposes.

 

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Item 8. Financial Statements and Supplementary Data.

Report of Independent Registered Public Accounting Firm

109

Consolidated Balance Sheets as of December 31, 2019 and 2018

110

Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017

111

Consolidated Statements of Partners' Capital for the years ended December 31, 2019, 2018 and 2017

112

Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017

113

Notes to Consolidated Financial Statements

115

1. Organization, Business Operations and Presentation and Consolidation

115

2. Summary of Significant Accounting Policies

116

3. Revenue

122

4. Segment Information

124

5. Property, Plant and Equipment, Net

128

6. Amortizing Intangible Assets

130

7. Goodwill

131

8. Equity Method Investments

131

9. Deferred Revenue

133

10. Debt

135

11. Financial Instruments

138

12. Partners' Capital and Mezzanine Capital

139

13. Earnings Per Unit

143

14. Unit-Based and Noncash Compensation

143

15. Related-Party Transactions

145

16. Leases, Commitments and Contingencies

145

17. Dispositions, Drop Down Transactions and Restructuring

149

18. Condensed Consolidated Financial Information

151

19. Unaudited Quarterly Financial Data

160

20. Subsequent Events

160

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Summit Midstream GP, LLC and the unitholders of Summit Midstream Partners, LP
Houston, Texas

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Summit Midstream Partners, LP and subsidiaries (the "Partnership") as of December 31, 2019 and 2018, the related consolidated statements of operations, partners’ capital, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, based on our audits and the report of the other auditors, the financial statements present fairly, in all material respects, the financial position of the Partnership as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We did not audit the financial statements of Ohio Gathering Company, L.L.C. (“Ohio Gathering”) as of and for the years ended December 31, 2019, 2018, and 2017, the Partnership’s investment in which is accounted for by use of the equity method. The accompanying financial statements of the Partnership include its equity investment in Ohio Gathering of $275,000,000 and $642,036,000 as of December 31, 2019 and 2018, respectively, and its loss from equity method investee in Ohio Gathering of $329,736,000, $11,085,000, and $1,823,000 for the years ended December 31, 2019, 2018 and 2017, respectively. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for Ohio Gathering prior to the impairment loss discussed in Note 8, which was audited by us, is based solely on the report of the other auditors.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, based on the criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 9, 2020 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Atlanta, Georgia

March 9, 2020

 

We have served as the Partnership's auditor since 2009.

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

 

 

 

December 31,

 

 

December 31,

 

 

 

2019

 

 

2018

 

 

 

(In thousands, except unit amounts)

 

Assets

 

 

 

 

 

 

 

 

Current assets:

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

4,948

 

 

$

4,345

 

Restricted cash

 

 

27,392

 

 

 

 

Accounts receivable

 

 

102,118

 

 

 

97,936

 

Other current assets

 

 

5,018

 

 

 

3,971

 

Total current assets

 

 

139,476

 

 

 

106,252

 

Property, plant and equipment, net

 

 

1,882,251

 

 

 

1,963,713

 

Intangible assets, net

 

 

232,278

 

 

 

273,416

 

Goodwill

 

 

 

 

 

16,211

 

Investment in equity method investees

 

 

309,728

 

 

 

649,250

 

Other noncurrent assets

 

 

9,718

 

 

 

11,720

 

Total assets

 

$

2,573,451

 

 

$

3,020,562

 

 

 

 

 

 

 

 

 

 

Liabilities and Capital

 

 

 

 

 

 

 

 

Current liabilities:

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

24,415

 

 

$

38,414

 

Accrued expenses

 

 

11,482

 

 

 

21,963

 

Due to affiliate

 

 

311

 

 

 

240

 

Deferred revenue

 

 

13,493

 

 

 

11,467

 

Ad valorem taxes payable

 

 

8,477

 

 

 

10,550

 

Accrued interest

 

 

12,311

 

 

 

12,286

 

Accrued environmental remediation

 

 

1,725

 

 

 

2,487

 

Other current liabilities

 

 

11,933

 

 

 

12,645

 

Total current liabilities

 

 

84,147

 

 

 

110,052

 

Long-term debt

 

 

1,470,299

 

 

 

1,257,731

 

Noncurrent Deferred Purchase Price Obligation

 

 

178,453

 

 

 

383,934

 

Noncurrent deferred revenue

 

 

38,709

 

 

 

39,504

 

Noncurrent accrued environmental remediation

 

 

2,926

 

 

 

3,149

 

Other noncurrent liabilities

 

 

7,951

 

 

 

4,968

 

Total liabilities

 

 

1,782,485

 

 

 

1,799,338

 

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 (93,493,473 units issued and outstanding

    at December 31, 2019 and 73,390,853 units issued and outstanding

    at December 31, 2018)

 

 

469,900

 

 

 

902,358

 

General Partner interests (zero units issued and outstanding at

    December 31, 2019 and 1,490,999 units issued and outstanding

    at December 31, 2018)

 

 

 

 

 

25,250

 

Total partners' capital

 

 

763,516

 

 

 

1,221,224

 

Total liabilities, mezzanine capital and partners' capital

 

$

2,573,451

 

 

$

3,020,562

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

 

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

 

 

97,587

 

 

 

96,878

 

 

 

93,882

 

General and administrative

 

 

54,139

 

 

 

52,877

 

 

 

54,681

 

Depreciation and amortization

 

 

110,206

 

 

 

107,100

 

 

 

115,475

 

Transaction costs

 

 

1,788

 

 

 

 

 

 

73

 

(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

 

 

402,340

 

 

 

371,702

 

 

 

510,577

 

Other income (expense)

 

 

451

 

 

 

(169

)

 

 

298

 

Interest expense

 

 

(74,429

)

 

 

(60,535

)

 

 

(68,131

)

Early extinguishment of debt

 

 

 

 

 

 

 

 

(22,039

)

Deferred Purchase Price Obligation

 

 

1,982

 

 

 

(20,975

)

 

 

200,322

 

(Loss) income before income taxes and loss

   from equity method investees

 

 

(30,808

)

 

 

53,272

 

 

 

88,614

 

Income tax expense

 

 

(1,174

)

 

 

(33

)

 

 

(341

)

Loss from equity method investees

 

 

(337,851

)

 

 

(10,888

)

 

 

(2,223

)

Net (loss) income

 

$

(369,833

)

 

$

42,351

 

 

$

86,050

 

Less:

 

 

 

 

 

 

 

 

 

 

 

 

Net income attributable to noncontrolling interest

 

 

 

 

 

168

 

 

 

363

 

Net (loss) income attributable to SMLP

 

 

(369,833

)

 

 

42,183

 

 

 

85,687

 

Net income attributable to General Partner,

    including IDRs

 

 

12

 

 

 

9,384

 

 

 

10,202

 

Net (loss) income attributable to limited partners

 

 

(369,845

)

 

 

32,799

 

 

 

75,485

 

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

 

$

(398,403

)

 

$

4,299

 

 

$

71,922

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) income per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

Common unit – basic

 

$

(4.84

)

 

$

0.06

 

 

$

0.99

 

Common unit – diluted

 

$

(4.84

)

 

$

0.06

 

 

$

0.98

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average limited partner units outstanding:

 

 

 

 

 

 

 

 

 

 

 

 

Common units – basic

 

 

82,365

 

 

 

73,304

 

 

 

72,705

 

Common units – diluted

 

 

82,365

 

 

 

73,615

 

 

 

73,047

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS' CAPITAL

 

 

 

Partners' capital

 

 

 

 

 

 

 

 

 

 

 

Limited partners

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Series A Preferred Units

 

 

Common

 

 

General Partner

 

 

Noncontrolling interest

 

 

Total

 

 

 

(In thousands)

 

Partners' capital, January 1, 2017

 

$

 

 

$

1,129,132

 

 

$

29,294

 

 

$

11,247

 

 

$

1,169,673

 

Net income

 

 

3,563

 

 

 

71,922

 

 

 

10,202

 

 

 

363

 

 

 

86,050

 

Distributions to unitholders

 

 

(2,375

)

 

 

(167,062

)

 

 

(12,041

)

 

 

 

 

 

(181,478

)

Unit-based compensation

 

 

 

 

 

7,878

 

 

 

 

 

 

 

 

 

7,878

 

Tax withholdings on vested SMLP

    LTIP awards

 

 

 

 

 

(2,236

)

 

 

 

 

 

 

 

 

(2,236

)

Issuance of Series A Preferred

    Units, net of offering costs

 

 

293,238

 

 

 

 

 

 

 

 

 

 

 

 

293,238

 

ATM Program issuances, net of costs

 

 

 

 

 

17,078

 

 

 

 

 

 

 

 

 

17,078

 

Contribution from General Partner

 

 

 

 

 

 

 

 

465

 

 

 

 

 

 

465

 

Purchase of noncontrolling interest

 

 

 

 

 

 

 

 

 

 

 

(797

)

 

 

(797

)

Other

 

 

 

 

 

(202

)

 

 

 

 

 

 

 

 

(202

)

Partners' capital, December 31,

    2017, as reported

 

$

294,426

 

 

$

1,056,510

 

 

$

27,920

 

 

$

10,813

 

 

$

1,389,669

 

January 1, 2018 impact of Topic 606

    day 1 adoption

 

 

 

 

 

4,130

 

 

 

84

 

 

 

 

 

 

4,214

 

Partners' capital, January 1, 2018

 

 

294,426

 

 

 

1,060,640

 

 

 

28,004

 

 

 

10,813

 

 

 

1,393,883

 

Net income

 

 

28,500

 

 

 

4,299

 

 

 

9,384

 

 

 

168

 

 

 

42,351

 

Distributions to unitholders

 

 

(28,500

)

 

 

(168,567

)

 

 

(12,138

)

 

 

 

 

 

(209,205

)

Unit-based compensation

 

 

 

 

 

8,088

 

 

 

 

 

 

 

 

 

8,088

 

Tax withholdings on vested SMLP

    LTIP awards

 

 

 

 

 

(1,974

)

 

 

 

 

 

 

 

 

(1,974

)

Purchase of noncontrolling interest

 

 

 

 

 

 

 

 

 

 

 

(10,981

)

 

 

(10,981

)

Other

 

 

(810

)

 

 

(128

)

 

 

 

 

 

 

 

 

(938

)

Partners' capital, December 31, 2018

 

$

293,616

 

 

$

902,358

 

 

$

25,250

 

 

$

 

 

$

1,221,224

 

Net income (loss)

 

 

28,500

 

 

 

(398,403

)

 

 

12

 

 

 

 

 

 

(369,891

)

Conversion of General Partner

    economic interests

 

 

 

 

 

22,222

 

 

 

(22,222

)

 

 

 

 

 

 

Distributions to unitholders

 

 

(28,500

)

 

 

(113,584

)

 

 

(3,040

)

 

 

 

 

 

(145,124

)

Unit-based compensation

 

 

 

 

 

8,171

 

 

 

 

 

 

 

 

 

8,171

 

Tax withholdings on vested SMLP

    LTIP awards

 

 

 

 

 

(2,614

)

 

 

 

 

 

 

 

 

(2,614

)

DPPO partial settlement

 

 

 

 

 

51,750

 

 

 

 

 

 

 

 

 

51,750

 

Partners' capital, December 31, 2019

 

$

293,616

 

 

$

469,900

 

 

$

 

 

$

 

 

$

763,516

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Cash flows from operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

Net (loss) income

 

$

(369,833

)

 

$

42,351

 

 

$

86,050

 

Adjustments to reconcile net (loss) income to net

    cash provided by operating activities:

 

 

 

 

 

 

 

 

 

 

 

 

Depreciation and amortization

 

 

111,426

 

 

 

106,767

 

 

 

114,872

 

Noncash lease expense

 

 

3,086

 

 

 

 

 

 

 

Amortization of debt issuance costs

 

 

4,411

 

 

 

4,285

 

 

 

4,158

 

Deferred Purchase Price Obligation

 

 

(1,982

)

 

 

20,975

 

 

 

(200,322

)

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

 

 

(4,334

)

 

 

(21,535

)

 

 

25,063

 

Trade accounts payable

 

 

(95

)

 

 

81

 

 

 

(3,246

)

Accrued expenses

 

 

(10,327

)

 

 

9,464

 

 

 

1,110

 

Due from (to) affiliate

 

 

71

 

 

 

(848

)

 

 

830

 

Deferred revenue, net

 

 

1,683

 

 

 

5,355

 

 

 

(40,758

)

Ad valorem taxes payable

 

 

(1,525

)

 

 

2,221

 

 

 

(2,259

)

Accrued interest

 

 

25

 

 

 

(24

)

 

 

(5,173

)

Accrued environmental remediation, net

 

 

(2,284

)

 

 

(3,808

)

 

 

(4,109

)

Other, net

 

 

(6,489

)

 

 

972

 

 

 

(348

)

Net cash provided by operating activities

 

 

182,337

 

 

 

227,929

 

 

 

237,832

 

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

)

 

 

 

 

 

 

Purchase of noncontrolling interest

 

 

 

 

 

(10,981

)

 

 

(797

)

Other, net

 

 

313

 

 

 

(284

)

 

 

(458

)

Net cash used in investing activities

 

 

(90,870

)

 

 

(216,279

)

 

 

(148,683

)

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(continued)

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Cash flows from financing activities:

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to unitholders

 

 

(116,624

)

 

 

(180,705

)

 

 

(179,103

)

Distributions to Series A Preferred unitholders

 

 

(28,500

)

 

 

(28,500

)

 

 

(2,375

)

Borrowings under Revolving Credit Facility

 

 

369,000

 

 

 

289,000

 

 

 

247,500

 

Repayments under Revolving Credit Facility

 

 

(158,000

)

 

 

(84,000

)

 

 

(634,500

)

Repayment of Deferred Purchase Price Obligation

 

 

(151,750

)

 

 

 

 

 

 

Debt issuance costs

 

 

(499

)

 

 

(344

)

 

 

(16,390

)

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 issuance of Series A preferred units, net of costs

 

 

27,392

 

 

 

 

 

 

293,238

 

Contribution from General Partner

 

 

 

 

 

 

 

 

465

 

Issuance of senior notes

 

 

 

 

 

 

 

 

500,000

 

Tender and redemption of senior notes

 

 

 

 

 

 

 

 

(300,000

)

Other, net

 

 

(4,491

)

 

 

(4,186

)

 

 

(3,128

)

Net cash used in financing activities

 

 

(63,472

)

 

 

(8,735

)

 

 

(95,147

)

Net change in cash, cash equivalents and restricted cash

 

 

27,995

 

 

 

2,915

 

 

 

(5,998

)

Cash, cash equivalents and restricted cash, beginning of period

 

 

4,345

 

 

 

1,430

 

 

 

7,428

 

Cash, cash equivalents and restricted cash, end of period (1)

 

$

32,340

 

 

$

4,345

 

 

$

1,430

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Supplemental cash flow disclosures:

 

 

 

 

 

 

 

 

 

 

 

 

Cash interest paid

 

$

76,883

 

 

$

64,678

 

 

$

71,488

 

Less capitalized interest

 

 

6,974

 

 

 

8,497

 

 

 

2,579

 

Interest paid (net of capitalized interest)

 

$

69,909

 

 

$

56,181

 

 

$

68,909

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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

 

DPPO partial settlement

 

 

51,750

 

 

 

 

 

 

 

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 assets relating to Topic 842

 

 

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

 

$

4,948

 

 

$

4,345

 

 

$

1,430

 

Restricted cash

 

 

27,392

 

 

 

 

 

 

 

Total cash, cash equivalents and restricted cash

 

$

32,340

 

 

$

4,345

 

 

$

1,430

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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SUMMIT MIDSTREAM PARTNERS, LP AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1. ORGANIZATION, BUSINESS OPERATIONS AND PRESENTATION AND CONSOLIDATION

Organization. SMLP, a Delaware limited partnership, was formed in May 2012 and began operations in October 2012. SMLP is a growth-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. Our business activities are conducted through various operating subsidiaries, each of which is owned or controlled by our wholly owned subsidiary holding company, Summit Holdings, a Delaware limited liability company. References to the "Partnership," "we," or "our" refer collectively to SMLP and its subsidiaries.

The General Partner, a Delaware limited liability company, manages our operations and activities. Summit Investments, a Delaware limited liability company, is the ultimate owner of our General Partner and has the right to appoint the entire Board of Directors. Summit Investments is controlled by Energy Capital Partners.

Summit Investments owned an approximate 2% general partner interest in SMLP (including the IDRs) until March 22, 2019. On March 22, 2019, we executed an equity restructuring agreement with the General Partner and SMP Holdings pursuant to which the IDRs and the 2% general partner interest were converted into a non-economic general partner interest in exchange for 8,750,000 common units which were issued to SMP Holdings (the “Equity Restructuring”). As of December 31, 2019, SMP Holdings, a wholly owned subsidiary of Summit Investments, beneficially owned 45,318,866 SMLP common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 SMLP common units.

Neither SMLP nor its subsidiaries have any employees. All of the personnel that conduct our business are employed by Summit Investments, but these individuals are sometimes referred to as our employees.

Business Operations.  We provide natural gas gathering, compression, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term, fee-based agreements with our customers. Our results are primarily driven by the volumes of natural gas that we gather, compress, treat and/or process as well as by the volumes of crude oil and produced water that we gather. We are the owner-operator of, or have significant ownership interests in, the following gathering and transportation systems:

 

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;

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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.

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 for details on the sale of Tioga Midstream.

In June 2019, in conjunction with the Double E Project, Summit Permian Transmission entered into a definitive joint venture agreement (the “Agreement”) with an affiliate of Double E’s foundation shipper (the “JV Partner”) to fund the capital expenditures associated with the Double E Project. Refer to Note 8 for additional details.

Other than our investments in Double E and Ohio Gathering, all of our business activities are conducted through wholly owned operating subsidiaries

Presentation and Consolidation.  We prepare our consolidated financial statements in accordance with GAAP as established by the FASB. We make estimates and assumptions that affect the reported amounts of assets and liabilities at the balance sheet dates, including fair value measurements, the reported amounts of revenues and expenses and the disclosure of commitments and contingencies. Although management believes these estimates are reasonable, actual results could differ from its estimates.

The consolidated financial statements include the assets, liabilities and results of operations of SMLP and its subsidiaries. All intercompany transactions among the consolidated entities have been eliminated in consolidation. Comprehensive income or loss is the same as net income or loss for all periods presented.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash, Cash Equivalents and Restricted Cash.  We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. Cash that is held by a major bank and has restrictions on its availability to us is classified as restricted cash. See Note 12 for additional information.

Accounts Receivable.  Accounts receivable relate to gathering and other services provided to our customers and other counterparties. We evaluate the collectability of accounts receivable and the need for an allowance for doubtful accounts based on customer-specific facts and circumstances. To the extent we doubt the collectability of a specific customer or counterparty receivable, we recognize an allowance for doubtful accounts. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or a receivable amount is deemed otherwise unrealizable.  

Property, Plant and Equipment.  We record property, plant and equipment at historical cost of construction or fair value of the assets at acquisition. We capitalize expenditures that extend the useful life of an asset or enhance its productivity or efficiency from its original design over the expected remaining period of use. For maintenance and repairs that do not add capacity or extend the useful life of an asset, we recognize expenditures as an expense as incurred. We capitalize project costs incurred during construction, including interest on funds borrowed to finance the construction of facilities, as construction in progress.

We record depreciation on a straight-line basis over an asset’s estimated useful life. We base our estimates for useful life on various factors including age (in the case of acquired assets), manufacturing specifications, technological advances and historical data concerning useful lives of similar assets. Estimates of useful lives follow.

 

Useful lives

(In years)

 

(In years)

Gathering and processing systems and related equipment

12-30

Other

4-15

Construction in progress is depreciated consistent with its applicable asset class once it is placed in service. Land and line fill are not depreciated.  

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We base an asset’s carrying value on estimates, assumptions and judgments for useful life and salvage value. Upon sale, retirement or other disposal, we remove the carrying value of an asset and its accumulated depreciation from our balance sheet and recognize the related gain or loss, if any.

Accrued capital expenditures are reflected in trade accounts payable.  

Asset Retirement Obligations.  We record a liability for asset retirement obligations only if and when a future asset retirement obligation with a determinable life is identified. For identified asset retirement obligations, we then evaluate whether the expected date and related costs of retirement can be estimated. We have concluded that our gathering and processing assets have an indeterminate life because they are owned and will operate for an indeterminate period when properly maintained. Because we did not have sufficient information to reasonably estimate the amount or timing of such obligations and we have no current plan to discontinue use of any significant assets, we did not provide for any asset retirement obligations as of December 31, 2019 or 2018.  

Amortizing Intangibles.  Upon the acquisition of DFW Midstream, certain of its gas gathering contracts were deemed to have above-market pricing structures. We have recognized the above-market contracts as favorable gas gathering contracts. We amortize the favorable contracts using a straight-line method over the contract’s estimated useful life. We define useful life as the period over which the contract is expected to contribute to our future cash flows. These contracts have original terms ranging from 10 years to 20 years. We recognize the amortization expense associated with these contracts in Other revenues.

We amortize all other gas gathering contracts, or contract intangibles, over the period of economic benefit based upon expected revenues over the life of the contract. The useful life of these contracts ranges from 3 years to 25 years. We recognize the amortization expense associated with these contracts in Depreciation and amortization expense.

We have rights-of-way associated with city easements and easements granted within existing rights-of-way. We amortize these intangible assets over the shorter of the contractual term of the rights-of-way or the estimated useful life of the gathering system. The contractual terms of the rights-of-way range from 20 years to 30 years. We recognize the amortization expense associated with rights-of-way assets in Depreciation and amortization expense.

Goodwill.  Goodwill represents consideration paid in excess of the fair value of the net identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on September 30. 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. As of December 31, 2019, we did not have a goodwill balance on our consolidated balance sheet.

Equity Method Investments.  We account for investments in which we exercise significant influence using the equity method so long as we (i) do not control the investee and (ii) are not the primary beneficiary. We recognize these investments in investment in equity method investees in the accompanying consolidated balance sheets. We recognized (i) our proportionate share of earnings or loss in net income for Ohio Gathering, on a one-month lag, and (ii) an other-than-temporary impairment for Ohio Gathering, based on the financial information available to us during the reporting period.

We recognize an other-than-temporary impairment for losses in the value of equity method investees when evidence indicates that the carrying amount is no longer supportable. Evidence of a loss in value might include, but would not necessarily be limited to, absence of an ability to recover the carrying amount of the investment or inability of the equity method investee to sustain an earnings capacity that would justify the carrying amount of the investment. A current fair value of an investment that is less than its carrying amount may indicate a loss in value of the investment. We evaluate our equity method investments whenever a triggering event exists that would indicate a need to assess the investment for potential impairment.  

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Other Noncurrent Assets.  Other noncurrent assets primarily consist of external costs incurred in connection with the closing of our Revolving Credit Facility and related amendments. We capitalize and then amortize these debt issuance costs on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Revolving Credit Facility debt issuance costs in interest expense.

Debt Issuance Costs.  Debt issuance costs, other than those associated with our Revolving Credit Facility, are reflected in the carrying value of the Senior Notes as an adjustment to the principal amount and amortized on a straight-line basis, which approximates the effect of the effective interest rate method, over the life of the respective debt instrument. We recognize the amortization of the Senior Notes debt issuance costs in interest expense.

Deferred Purchase Price Obligation.  We recognize a liability for the Deferred Purchase Price Obligation to reflect the present value of the estimated Remaining Consideration for the acquisition of the 2016 Drop Down Assets. In March 2016, we recognized the Deferred Purchase Price Obligation in connection with the 2016 Drop Down. On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest will accrue (and will be payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020 (see Note 17 for additional information).

Impairment of Long-Lived Assets.  We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. The carrying value of a long-lived asset (except goodwill) is not recoverable if it exceeds the sum of the undiscounted cash flows expected to result from its use and eventual disposition. If we conclude that an asset's carrying value will not be recovered through future cash flows, we recognize an impairment loss on the long-lived asset equal to the amount by which the carrying value exceeds its fair value. We determine fair value using either a market-based approach, an income-based approach or a combination of the two approaches.

Derivative Contracts.  We have commodity price exposure related to our sale of the physical natural gas we retain from certain DFW Midstream customers and our procurement of electricity to operate the DFW Midstream system's electric-drive compression assets. Our gas gathering agreements with certain DFW Midstream customers permit us to retain a certain quantity of natural gas that we gather to offset the power costs we incur to operate these electric-drive compression assets. We manage this direct exposure to natural gas and power prices through the use of forward power purchase contracts with wholesale power providers that require us to purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices based on the Henry Hub Index. We sell retainage natural gas at prices that are based on the Atmos Zone 3 Index. By basing the power prices on a system and basin-relevant market, we are able to closely associate the relationship between the compression electricity expense and natural gas retainage sales.  

Accounting standards related to derivative instruments and hedging activities allow for normal purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. We have designated these contracts as normal under the normal purchase and sale exception under the accounting standards for derivatives. We do not enter into risk management contracts for speculative purposes.

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Restructuring Costs.  Our restructuring costs are comprised primarily of employee termination costs related to headcount reductions. A liability for costs associated with an exit or disposal activity is recognized and measured initially at fair value only when the liability is incurred. Our restructuring charges also include relocation expenses and advisory costs. We reassess the liability periodically based on market conditions. Refer to Note 17 for additional details.

Fair Value of Financial Instruments.  The fair-value-measurement standard under GAAP defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The standard characterizes inputs used in determining fair value according to a hierarchy that prioritizes those inputs based upon the degree to which the inputs are observable. The three levels of the fair value hierarchy are as follows:  

 

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).  

Commitments and Contingencies.  We record accruals for loss contingencies when we determine that it is probable that a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. We recognize gain contingencies when their realization is assured beyond a reasonable doubt.

Noncontrolling Interest.  Noncontrolling interest represented the ownership interests of third-party entities in the net assets of our consolidated subsidiaries.

Revenue Recognition.  The majority of our revenue is derived from long-term, fee-based contracts with original terms of up to 25 years. We account for revenue in accordance with Topic 606, which we adopted on January 1, 2018, using the modified retrospective method. See below for further discussion of the adoption.

We recognize revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in natural gas, NGLs and condensate sales; the associated expense is included in operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

We provide gathering and/or processing services principally under contracts that contain one or more of the following arrangements:  

 

Fee-based arrangements. Under 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.  

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Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs.  

Certain of our gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.  

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 making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.

Unit-Based Compensation.  For awards of unit-based compensation, we determine a grant date fair value and recognize the related compensation expense in the statements of operations over the vesting period of the respective awards.

Income Taxes.  As a partnership, we are generally not subject to federal and state income taxes, except as noted below. However, our unitholders are individually responsible for paying federal and state income taxes on their share of our taxable income. Net income or loss for GAAP purposes may differ significantly from taxable income reportable to our unitholders as a result of differences between the tax basis and the GAAP basis of assets and liabilities and the taxable income allocation requirements under our Partnership Agreement. The aggregate difference in the basis of the Partnership’s net assets for financial and income tax purposes cannot be readily determined as the Partnership does not have access to the information about each partner’s tax attributes related to the Partnership.

In general, legal entities that are chartered, organized or conducting business in the state of Texas are subject to a franchise tax (the "Texas Margin Tax"). The Texas Margin Tax has the characteristics of an income tax because it is determined by applying a tax rate to a tax base that considers both revenues and expenses. Our financial statements reflect provisions for these tax obligations.    

Earnings or Loss Per Unit.  We determine basic EPU by dividing the net income or loss that is attributed, in accordance with the net income and loss allocation provisions of our Partnership Agreement, to common limited partners under the two-class method, after deducting (i) any payment of IDRs, by the weighted-average number of limited partner units outstanding (for periods presented through the Equity Restructuring), (ii) the General Partner's approximate 2% interest in net income or loss (for periods presented up through the Equity Restructuring), and (iii) net income attributable to Series A Preferred Units and Subsidiary Series A Preferred Units. Diluted EPU reflects the potential dilution that could occur if securities or other agreements to issue common units, such as unit-based compensation, were exercised, settled or converted into common units and included in the weighted-average number of units outstanding. When it is determined that potential common units resulting from an award subject to performance or market conditions should be included in the diluted EPU calculation, the impact is reflected by applying the treasury stock method.

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Environmental Matters.  We are subject to various federal, state and local laws and regulations relating to the protection of the environment. Liabilities for loss contingencies, including environmental remediation costs, arising from claims, assessments, litigation, fines and penalties and other sources are charged to expense when it is probable that a liability has been incurred and the amount of the assessment and/or remediation can be reasonably estimated. We accrue for losses associated with environmental remediation obligations when such losses are probable and reasonably estimable. Such accruals are adjusted as further information develops or circumstances change. Recoveries of environmental remediation costs from other parties or insurers are recorded as assets when their realization is assured beyond a reasonable doubt.  

Recent Accounting Pronouncements. Accounting standard setters frequently issue new or revised accounting rules. We review new pronouncements to determine the impact, if any, on our financial statements. Accounting standards that have or could possibly have a material effect on our financial statements are discussed below.

Recently Adopted Accounting Pronouncements. We have recently adopted the following accounting pronouncement: 

 

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 (“ROU”) asset which represents the right to use, or to control the use of, specified assets for a lease term. The ROU asset is included in the Property, plant and equipment, net caption on the consolidated balance sheet; and (ii) a $5.4 million lease liability for the obligation to make lease payments arising from the leases. The lease liability is included in the Other current liabilities and Other noncurrent liabilities captions on the consolidated balance sheet. The comparative information has not been adjusted and is reported under the accounting standards in effect for those periods. Refer to Note 16 for additional information.

Accounting Pronouncements Pending Adoption. We have not yet adopted the following accounting pronouncements as of December 31, 2019:

 

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.

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3. REVENUE

The majority of our revenue is derived from long-term, fee-based contracts with our customers, which include original terms of up to 25 years. We recognize revenue earned from fee-based gathering, compression, treating and processing services in gathering services and related fees. We also earn revenue in the Williston Basin and Permian Basin reporting segments from the sale of physical natural gas purchased from our customers under certain percent-of-proceeds arrangements. Under ASC Topic 606, these gathering contracts are presented net within cost of natural gas and NGLs. We sell natural gas that we retain from certain customers in the Barnett Shale reporting segment to offset the power expenses of the electric-driven compression on the DFW Midstream system. We also sell condensate and NGLs retained from certain of our gathering services in the Piceance Basin and Permian Basin reporting segments. Revenues from the sale of natural gas and condensate are recognized in Natural gas, NGLs and condensate sales; the associated expense is included in Operation and maintenance expense. Certain customers reimburse us for costs we incur on their behalf. We record costs incurred and reimbursed by our customers on a gross basis, with the revenue component recognized in Other revenues.

The transaction price in our contracts is primarily based on the volume of natural gas, crude oil or produced water transferred by our gathering systems to the customer’s agreed upon delivery point multiplied by the contractual rate. For contracts that include MVCs, variable consideration up to the MVC will be included in the transaction price. For contracts that do not include MVCs, we do not estimate variable consideration because the performance obligations are completed and settled on a daily basis. For contracts containing noncash consideration such as fuel received in-kind, we measure the transaction price at the point of sale when the volume, mix and market price of the commodities are known.

We have contracts with MVCs that are variable and constrained. Contracts with greater than monthly MVCs are reviewed on a quarterly basis and adjustments to those estimates are made during each respective reporting period, if necessary.

The transaction price is allocated if the contract contains more than one performance obligation such as contracts that include MVCs. The transaction price allocated is based on the MVC for the applicable measurement period.

Performance obligations.  The majority of our contracts have a single performance obligation which is either to provide gathering services (an integrated service) or sell natural gas, NGLs and condensate, which are both satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. We also have certain contracts with multiple performance obligations. They include an option for the customer to acquire additional services such as contracts containing MVCs. These performance obligations would also be satisfied when the related natural gas, crude oil and produced water are received and transferred to an agreed upon delivery point. In these instances, we allocate the contract’s transaction price to each performance obligation using our best estimate of the standalone selling price of each service in the contract.

Performance obligations for gathering services are generally satisfied over time. We utilize either an output method (i.e., measure of progress) for guaranteed, stand-ready service contracts or an asset/system delivery time estimate for non-guaranteed, as-available service contracts.

Performance obligations for the sale of natural gas, NGLs and condensate are satisfied at a point in time. There are no significant judgments for these transactions because the customer obtains control based on an agreed upon delivery point.

Certain of our gathering and/or processing agreements provide for monthly or annual MVCs. Under these MVCs, our customers agree to ship and/or process a minimum volume of production on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contracted measurement period if its actual throughput volumes are less than its contractual MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period exceed its MVC for that contracted measurement period.  

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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.

Our services are typically billed on a monthly basis and we do not offer extended payment terms. We do not have contracts with financing components.  

The following table presents estimated revenue expected to be recognized over the remaining contract period related to performance obligations that are unsatisfied and are comprised of estimated MVC shortfall payments.

We applied the practical expedient in paragraph 606-10-50-14 of Topic 606 for certain arrangements that we consider optional purchases (i.e., there is no enforceable obligation for the customer to make purchases) and those amounts are therefore excluded from the table.

 

 

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

 

 

 

Revenue by Category.  In the following table, revenue is disaggregated by geographic area and major products and services. Ohio Gathering is excluded from the tables below due to equity method accounting. For more detailed information about reportable segments, see Note 4.

 

 

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

 

 

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Contract balances.  Contract assets relate to our rights to consideration for work completed but not billed at the reporting date and consist of the estimated MVC shortfall payments expected from our customers and unbilled activity associated with contributions in aid of construction. Contract assets are transferred to trade receivables when the rights become unconditional. The following table provides information about contract assets from contracts with customers:

 

 

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

 

As of December 31, 2019, receivables with customers totaled $90.4 million and contract assets totaled $3.9 million which were included in the Accounts receivable caption on the consolidated balance sheet.

As of December 31, 2018, receivables with customers totaled $82.9 million and contract assets totaled $8.8 million which were included in the Accounts receivable caption on the consolidated balance sheet.

Contract liabilities (deferred revenue) relate to the advance consideration received from customers primarily for contributions in aid of construction. We recognize contract liabilities under these arrangements in revenue over the contract period. For the years ended December 31, 2019 and 2018, we recognized $10.1 million and $10.8 million, respectively, of gathering services and related fees which was included in the contract liability balance as of the beginning of the period. See Note 9 for additional details.

4. SEGMENT INFORMATION

As of December 31, 2019, our reportable segments are:

 

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.  

Until March 22, 2019, we owned Tioga Midstream, a crude oil, produced water and associated natural gas gathering system operating in the Williston Basin. Until December 1, 2019, we owned certain assets in the Red Rock Gathering system operating in the Piceance Basin. Refer to Note 17 to the consolidated financial statements for details on the sale of Tioga Midstream and on the sale of certain assets in the Red Rock Gathering system.

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.

The Ohio Gathering reportable segment includes our investment in Ohio Gathering. Income or loss from equity method investees, as reflected on the statements of operations, relates to Ohio Gathering and is recognized and disclosed on a one-month lag (see Note 8).

For the year ended December 31, 2019, other than the investment activity described in Note 8, Double E did not have any results of operations given that the Double E Project is currently under development. The Double E Project is expected to be operational in the third quarter of 2021.

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Corporate and Other represents those results that are: (i) not specifically attributable to a reportable segment; (ii) not individually reportable (such as Double E); or (iii) that have not been allocated to our reportable segments for the purpose of evaluating their performance, including certain general and administrative expense items, certain natural gas and crude oil marketing services and transaction costs.

Assets by reportable segment follow.

 

 

 

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

 

 

82,506

 

 

 

44,181

 

 

 

22,406

 

Eliminations

 

 

 

 

 

(4,319

)

 

 

(249

)

Total assets

 

$

2,573,451

 

 

$

3,020,562

 

 

$

2,894,793

 

 

(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.

Revenues by reportable segment follow.

 

 

 

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.

Counterparties accounting for more than 10% of total revenues were as follows:

 

 

 

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

%

 

*

 

Counterparty D - Barnett Shale

 

*

 

 

*

 

 

*

 

 

(1) Excludes revenues earned by Ohio Gathering due to equity method accounting.

* Less than 10%

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Depreciation and amortization, including the amortization expense associated with our favorable and unfavorable (for 2018) gas gathering contracts as reported in other revenues, by reportable segment follows.

 

 

 

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

 

 

2,604

 

 

 

1,743

 

 

 

1,118

 

Total depreciation and amortization

 

$

111,426

 

 

$

106,767

 

 

$

114,872

 

 

(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.

Cash paid for capital expenditures by reportable segment follow.

 

 

 

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.

For the years ended December 31, 2019 and 2018, Corporate and Other includes cash paid of $1.6 million and $3.3 million, respectively, for corporate purposes; the remainder represents capital expenditures relating to the Double E Project.

We assess the performance of our reportable segments based on segment adjusted EBITDA. We define segment adjusted EBITDA as total revenues less total costs and expenses; plus (i) other income excluding interest income, (ii) our proportional adjusted EBITDA for equity method investees, (iii) depreciation and amortization, (iv) adjustments related to MVC shortfall payments, (v) adjustments related to capital reimbursement activity, (vi) unit-based and noncash compensation, (vii) change in the Deferred Purchase Price Obligation fair value, (viii) impairments (ix) other noncash expenses or losses, less other noncash income or gains and (x) restructuring expenses. We define proportional adjusted EBITDA for our equity method investees as the product of (i) total revenues less total expenses, excluding impairments and other noncash income or expense items, and amortization for deferred contract costs; and (ii) our ownership interest in Ohio Gathering during the respective period.

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For the purpose of evaluating segment performance, we exclude the effect of Corporate and Other revenues and expenses, such as certain general and administrative expenses (including compensation-related expenses and professional services fees), certain natural gas and crude oil marketing services, transaction costs, interest expense, change in the Deferred Purchase Price Obligation fair value and income tax expense or benefit from segment adjusted EBITDA.

Segment adjusted EBITDA by reportable segment follows.

 

 

 

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

 

 

A reconciliation of income or loss before income taxes and income or loss from equity method investees to total of reportable segments' measures of profit or loss follows.

 

 

 

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

 

$

(30,808

)

 

$

53,272

 

 

$

88,614

 

Add:

 

 

 

 

 

 

 

 

 

 

 

 

Corporate and Other expense

 

 

40,639

 

 

 

38,917

 

 

 

39,140

 

Interest expense

 

 

74,429

 

 

 

60,535

 

 

 

68,131

 

Early extinguishment of debt

 

 

 

 

 

 

 

 

22,039

 

Deferred Purchase Price Obligation

 

 

(1,982

)

 

 

20,975

 

 

 

(200,322

)

Depreciation and amortization

 

 

111,426

 

 

 

106,767

 

 

 

114,872

 

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

 

 

For the years ended December 31, 2019 and 2018, adjustments related to MVC shortfall payments recognize the earnings from MVC shortfall payments ratably over the term of the associated MVC (see Note 3).

Contributions in aid of construction are recognized over the remaining term of the respective contract. We include adjustments related to capital reimbursement activity in our calculation of segment adjusted EBITDA to account for revenue recognized from contributions in aid of construction.

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For the year ended December 31, 2017, we included adjustments related to MVC shortfall payments in our calculation of segment adjusted EBITDA to account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. With respect to the impact of a net change in deferred revenue for MVC shortfall payments, we treated increases in deferred revenue balances as a favorable adjustment to segment adjusted EBITDA, while decreases in deferred revenue balances were treated as an unfavorable adjustment to segment adjusted EBITDA. 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 recognize the shortfall payment. 

Adjustments related to MVC shortfall payments by reportable segment follow.

 

 

 

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

)

 

 

5. PROPERTY, PLANT AND EQUIPMENT, NET

Details on property, plant and equipment follow.

 

 

 

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

 

 

53,129

 

 

 

45,853

 

Total

 

 

2,324,932

 

 

 

2,350,846

 

Less accumulated depreciation

 

 

442,681

 

 

 

387,133

 

Property, plant and equipment, net

 

$

1,882,251

 

 

$

1,963,713

 

 

During 2019, 2018 and 2017, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment could be impaired. As such, we reviewed the assets that had been identified as potentially impaired and estimated the fair value of the identified property, plant and equipment using a market-based approach.

In December 2019, 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 based on the expected consideration and the carrying value for the Red Rock Gathering system assets. See Note 17 for additional details.

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In December 2019, in connection with the cancellation of a project, we determined certain processing plant assets in the Permian Basin would no longer be utilized. As a result, we recorded an impairment charge of $0.7 million related to these assets in the fourth quarter of 2019. See Note 6 for additional details.

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, in the first quarter of 2019, we performed a recoverability assessment of certain assets within these reporting segments.

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 Barnett Shale, we determined, in the first quarter of 2019, 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. See Note 6 for additional details.

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 the other assets that had been identified as potentially impaired and recognized the long-lived asset impairments in the table below.  

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 related to the Bison Midstream system within the Williston Basin were not fully recoverable. We recorded an impairment charge of $101.9 million related to these assets after comparing the fair value of the long-lived assets to their carrying values. See Note 6 for additional details.

During 2019, 2018 and 2017, we recognized the following long-lived asset impairments, by segment. 

 

 

 

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

 

 

 

 

 

Our impairment determinations, in the context of these reviews, involved 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.  

Depreciation expense and capitalized interest follow.

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Depreciation expense

 

$

78,341

 

 

$

74,511

 

 

$

75,120

 

Capitalized interest

 

 

6,974

 

 

 

8,497

 

 

 

2,579

 

 

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6. AMORTIZING INTANGIBLE ASSETS

Details regarding our intangible assets, all of which are subject to amortization, follow.

 

 

 

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

 

 

In December 2019, in connection with the cancellation of a project, we determined certain rights-of-way intangible assets in the Permian Basin would no longer be utilized (see Note 5). As a result, we recorded an impairment charge of $0.6 million in the fourth quarter of 2019.

Also in early 2019, certain events occurred which indicated that certain long-lived assets relating to the Barnett Shale reporting segment could be impaired (see Note 5). 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 December 2017, in connection with certain strategic initiatives, we evaluated certain long-lived assets relating to the Bison Midstream system within the Williston Basin reporting segment (see Note 5). In connection with this evaluation, we evaluated the related intangible assets associated therewith for impairment consisting of contract intangible assets and rights-of-way intangible assets. We concluded the contract intangible assets were also impaired and, as a result, we recorded an impairment charge of $85.2 million.

We recognized amortization expense in Other revenues as follows:

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Amortization expense – favorable gas gathering contracts

 

$

(1,220

)

 

$

(1,555

)

 

$

(1,555

)

 

We recognized amortization expense in costs and expenses as follows:

 

 

 

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

 

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The estimated aggregate annual amortization expected to be recognized for as of December 31, 2019 for each of the five succeeding fiscal years follows.

 

 

 

Intangible assets

 

 

 

(In thousands)

 

2020

 

$

31,901

 

2021

 

 

28,209

 

2022

 

 

25,142

 

2023

 

 

25,088

 

2024

 

 

14,917

 

 

7. GOODWILL

Goodwill for the year ended December 31, 2018 of $16.2 million was related to the acquisition of the Mountaineer Midstream system in 2013.

Accumulated goodwill impairments by reportable segment for those reporting units that have previously recognized goodwill follow.

 

 

 

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

 

 

We evaluate goodwill 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. If the reporting unit’s fair value exceeds its carrying value, including goodwill, we conclude that the goodwill of the reporting unit has not been impaired and no further work is performed. If we determine that the reporting unit’s carrying value, including goodwill, exceeds its fair value, we recognize the excess of the carrying value over the fair value as a goodwill impairment loss.

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.

We had no impairments of goodwill for the years ended December 31, 2018 and 2017.

Fair Value Measurement.  Our impairment determinations, in the context of (i) our annual impairment evaluations and (ii) our other-than-annual impairment evaluations involved significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the valuations. As such, the fair value measurements utilized within these models are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources.

8. EQUITY METHOD INVESTMENTS

Double E

In June 2019, we formed Double E in connection with the Double E Project. Effective June 26, 2019, Summit Permian Transmission, a wholly owned and consolidated subsidiary of the Partnership, and our JV Partner executed the Agreement whereby Double E will provide natural gas transportation services from multiple receipt points in the Delaware Basin to various delivery points in and around the Waha Hub in Texas. In connection with the Agreement and the related Double E Project, the Partnership contributed total assets of approximately $23.6 million in exchange for a 70% ownership interest in Double E and our JV Partner contributed $7.3 million of cash in exchange for a 30% ownership interest in Double E. Concurrent with these contributions, and in accordance with the Agreement, Double E

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distributed $7.3 million to the Partnership. Subsequent to the formation of Double E, we also made additional cash investments of $18.3 million through December 2019.

Double E is deemed to be a variable interest entity as defined in GAAP. As of the date of the Agreement, Summit Permian Transmission was not deemed to be the primary beneficiary due to the JV Partner’s voting rights on significant matters. We account for our ownership interest in Double E as an equity method investment because we have significant influence over Double E. Our portion of Double E’s net assets, which was $34.7 million at December 31, 2019, is reported under the caption Investment in equity method investees on the consolidated balance sheet.

For the year ended December 31, 2019, other than the investment activity noted above, Double E did not have any results of operations given that the Double E Project is currently under development.

Ohio Gathering

Ohio Gathering owns, operates and is currently developing midstream infrastructure consisting of a liquids-rich natural gas gathering system, a dry natural gas gathering system and a condensate stabilization facility in the Utica Shale in southeastern Ohio. Ohio Gathering provides gathering services pursuant to primarily long-term, fee-based gathering agreements, which include acreage dedications.

Our initial investment in Ohio Gathering in 2014 included a $190.0 million payment to acquire a 1% interest from a third party, which included an option to increase our ownership to 40%, as well as a series of contributions directly to Ohio Gathering in 2014, which increased our ownership to 40%. Concurrent with and subsequent to the exercise of the option, the non-affiliated owners have retained their respective 60% ownership interest in Ohio Gathering (the "Non-affiliated Owners").

We account for our ownership interests in Ohio Gathering as an equity method investment because we have joint control with the Non-affiliated Owners, which gives us significant influence.

We recognized the $190.0 million paid for the initial 1% interest as an investment in Ohio Gathering at inception. In addition, Ohio Gathering assigned a value of $7.5 million to the exercise option, which it ultimately attributed to our capital account. Neither of the aforementioned transactions involved a flow of funds to or from Ohio Gathering. As such, they created a basis difference between our recorded investment in equity method investees and the amount attributed to us by Ohio Gathering within its financial statements.

In December 2019, we identified certain triggering events which indicated that our equity method investment in Ohio Gathering could be impaired. In accordance with ASC Topic 323, we completed an equity method impairment analysis to determine the equity method impairment charge to be recorded on our consolidated financial statements resulting from an other-than-temporary impairment. As a result of our analysis, an impairment charge of approximately $329.7 million was recorded in 2019 in Loss from equity method investments on the accompanying consolidated statements of operations.

The fair value of our investment in Ohio Gathering was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of approximately 9.0 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Gathering equity method investment represents a Level 3 measurement. As a result, actual results may differ from the estimates and assumptions made for purposes of this impairment analysis.

Also in December 2019, an impairment loss of long-lived assets was recognized by OCC. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded an impairment loss of $6.3 million in Loss from equity method investees in the consolidated statements of operations because the information was available to us.

In December 2018, Ohio Gathering was involved in legal proceedings relating to a dispute regarding pipeline right of way rights and associated trespass claims that took place prior to December 31, 2018. Ohio Gathering received a judgment on those proceedings in January 2019 and recorded an estimate of the legal exposure as of December 31, 2018. Although we recognize activity for Ohio Gathering on a one-month lag, we recorded the asset impairments and legal contingency in our results of operations for the year ending December 31, 2018 because the information was available to us. We recorded our then 40% share of the asset impairments and legal contingency amounting to $7.7 million in 2018 in Loss from equity method investees in the consolidated statements of operations.

As a result of our joint venture partner funding a disproportionate amount of the capital calls during the year ended December 31, 2019, our ownership interest in Ohio Gathering decreased from 40.0% at December 31, 2018, to 38.5% at December 31, 2019.

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A reconciliation of our 38.5% and 40% ownership interest in Ohio Gathering to our investment per Ohio Gathering's books and records follows for the years ending December 31, 2019 and 2018, respectively (in thousands).

 

 

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.

 

Summarized balance sheet information for OGC and OCC follows (amounts represent 100% of investee financial information).

 

 

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

 

Summarized statements of operations information for OGC and OCC follow (amounts represent 100% of investee financial information).

 

 

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

)

 

9. DEFERRED REVENUE

Certain of our gathering and/or processing agreements provide for monthly or annual MVCs. The amount of the shortfall payment is based on the difference between the actual throughput volume shipped and/or processed for the applicable period and the MVC for the applicable period, multiplied by the applicable gathering or processing fee.

Many of our gas gathering agreements contain provisions that can reduce or delay the cash flows that we expect to receive from our MVCs to the extent that a customer's actual throughput volumes are above or below its MVC for the applicable contracted measurement period. These provisions include the following: 

 

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). 

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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.

A rollforward of current deferred revenue follows.

 

 

 

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

 

 

A rollforward of noncurrent deferred revenue follows.

 

 

 

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

 

 

 

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10. DEBT

Debt consisted of the following:

 

 

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

)

Total long-term debt

 

$

1,470,299

 

 

$

1,257,731

 

 

(1) Issuance costs are being amortized over the life of the notes.

The aggregate amount of debt maturing during each of the years after December 31, 2019 are as follows (in thousands):

2020

 

$

 

2021

 

 

 

2022

 

 

977,000

 

2023

 

 

 

2024

 

 

 

Thereafter

 

 

500,000

 

Total long-term debt

 

$

1,477,000

 

Revolving Credit Facility. Summit Holdings has a senior secured revolving credit facility which allows for revolving loans, letters of credit and swingline loans. The Revolving Credit Facility has a $1.25 billion borrowing capacity, matures in May 2022, and includes a $250.0 million accordion feature. As of December 31, 2019, SMLP and the Guarantor Subsidiaries fully and unconditionally and jointly and severally guarantee, and pledge substantially all of their assets in support of, the indebtedness outstanding under the Revolving Credit Facility.

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In May 2017, Summit Holdings amended and restated its Revolving Credit Facility with a third amended and restated credit agreement which: (i) maintained the Revolving Credit Facility commitments of $1.25 billion, (ii) extended the maturity from November 2018 to May 2022, (iii) included a $250.0 million accordion feature, (iv) maintained the same leverage-based pricing and commitment fee grid, (v) increased the maximum permitted total leverage ratio, as defined in the credit agreement, from 5.00 to 1.00 to 5.50 to 1.00 and (vi) included a maximum permitted senior secured leverage ratio, as defined in the credit agreement, of 3.75 to 1.00. In June 2019, we executed the second amendment to the third amended and restated credit agreement that, among other things, made accommodations for the transactions contemplated by the Agreement and designated Double E as an unrestricted subsidiary under the Revolving Credit Facility. In December 2019, we executed the third amendment to the third amended and restated credit agreement that, among other things, designated the Non-Guarantor Subsidiaries as unrestricted subsidiaries under the Revolving Credit Facility.

Borrowings under the Revolving Credit Facility bear interest, at the election of Summit Holdings, at a rate based on the alternate base rate (as defined in the credit agreement) plus an applicable margin ranging from 0.75% to 1.75% or the adjusted Eurodollar rate (as defined in the credit agreement) plus an applicable margin ranging from 1.75% to 2.75%, with the commitment fee ranging from 0.30% to 0.50% in each case based on our relative leverage at the time of determination. At December 31, 2019, the applicable margin under LIBOR borrowings was 2.75%, the interest rate was 4.55% and the unused portion of the Revolving Credit Facility totaled $563.9 million, subject to a commitment fee of 0.50%, 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. See Note 16 for additional information on our letter of credit.

The Revolving Credit Facility is secured by the membership interests of Summit Holdings and the membership interests of the Guarantor Subsidiaries of Summit Holdings and by substantially all of the assets of Summit Holdings and its Guarantor Subsidiaries (subject to exclusions set forth in the credit agreement). The credit agreement contains affirmative and negative covenants customary for credit facilities of its size and nature that, among other things, limit or restrict the ability (i) to incur additional debt; (ii) to make investments; (iii) to engage in certain mergers, consolidations, acquisitions or sales of assets; (iv) to enter into swap agreements and power purchase agreements; (v) to enter into leases that would cumulatively obligate payments in excess of $50.0 million over any 12 -month period; and (vi) of Summit Holdings to make distributions, with certain exceptions, including the distribution of Available Cash (as defined in the SMLP Partnership Agreement) if no default or event of default then exists or would result therefrom and Summit Holdings is in pro forma compliance with its financial covenants. In addition, the Revolving Credit Facility requires Summit Holdings to maintain (i) a ratio of consolidated trailing 12 -month earnings before interest, income taxes, depreciation and amortization ("EBITDA") to net interest expense of not less than 2.5 to 1.0 as defined in the credit agreement, (ii) a ratio of total net indebtedness to consolidated trailing 12 -month EBITDA of not more than 5.50 to 1.00 and, (iii) a ratio of first lien net indebtedness to consolidated trailing 12 -month EBITDA of not more than 3.75 to 1.00.

As of December 31, 2019, we had $6.2 million of debt issuance costs attributable to our Revolving Credit Facility and related amendments which are included in Other noncurrent assets on the consolidated balance sheet.

As of December 31, 2019, we were in compliance with the Revolving Credit Facility's financial covenants. There were no defaults or events of default during the year ended December 31, 2019.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Finance Corp. (together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.5% senior unsecured notes maturing August 15, 2022 (the "5.5% Senior Notes" and, together with the 5.75% Senior Notes (defined below), the “Senior Notes”).

In 2018, we executed supplemental indentures to include OpCo, Summit Utica, Meadowlark Midstream and Tioga Midstream (through March 22, 2019) as guarantors concurrent with the purchase of a 1% noncontrolling interest held by a subsidiary of Summit Investments (see Note 12 to the consolidated financial statements for additional details). In 2019, we executed a partial release agreement that designated the Non-Guarantor Subsidiaries as unrestricted subsidiaries under the Senior Notes.

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The Guarantor Subsidiaries are 100% owned by a subsidiary of SMLP. The Guarantor Subsidiaries and SMLP fully and unconditionally and jointly and severally guarantee the Senior Notes. There are no significant restrictions on the ability of SMLP or Summit Holdings to obtain funds from its subsidiaries by dividend or loan. Finance Corp. has had no assets or operations since inception in 2013. We have no other independent assets or operations. At no time have the Senior Notes been guaranteed by the Co-Issuers.

5.75% Senior Notes. In February 2017, the Co-Issuers completed a public offering of $500.0 million of 5.75% senior unsecured notes maturing April 15, 2025. We pay interest on the 5.75% Senior Notes semi-annually in cash in arrears on April 15 and October 15 of each year. The 5.75% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.75% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. 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 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.

At any time prior to April 15, 2020, the Co-Issuers may redeem up to 35% of the aggregate principal amount of the 5.75% Senior Notes at a redemption price of 105.750% of the principal amount of the 5.75% Senior Notes, plus accrued and unpaid interest, if any, but not including, the redemption date, with an amount not greater than the net cash proceeds of certain equity offerings. On and after April 15, 2020, the Co-Issuers may redeem all or part of the 5.75% Senior Notes at a redemption price of 104.313% (with the redemption premium declining ratably each year to 100.000% on and after April 15, 2023), plus accrued and unpaid interest, if any, to, but not including, the redemption date. Debt issuance costs of $7.7 million are being amortized over the life of the 5.75% Senior Notes.

The 5.75% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.75% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.75% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.75% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $75.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.75% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.75% Senior Notes may declare all the 5.75% Senior Notes to be due and payable immediately.

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5.5% Senior Notes. We pay interest on the 5.5% Senior Notes semi-annually in cash in arrears on February 15 and August 15 of each year. The 5.5% Senior Notes are senior, unsecured obligations and rank equally in right of payment with all of our existing and future senior obligations. The 5.5% Senior Notes are effectively subordinated in right of payment to all of our secured indebtedness, to the extent of the collateral securing such indebtedness. We used the proceeds from the issuance of the 5.5% Senior Notes to repay a portion of the balance outstanding under our Revolving Credit Facility.

At any time prior to August 15, 2020, the Co-Issuers may redeem all or part of the 5.5% Senior Notes at a redemption price of 101.375% (with the redemption premium declining to 100.000% on and after August 15, 2020), plus accrued and unpaid interest, if any. Debt issuance costs of $5.1 million are being amortized over the life of the 5.5% Senior Notes.

The 5.5% Senior Notes' indenture restricts SMLP’s and the Co-Issuers’ ability and the ability of certain of their subsidiaries to: (i) incur additional debt or issue preferred stock; (ii) make distributions, repurchase equity or redeem subordinated debt; (iii) make payments on subordinated indebtedness; (iv) create liens or other encumbrances; (v) make investments, loans or other guarantees; (vi) sell or otherwise dispose of a portion of their assets; (vii) engage in transactions with affiliates; and (viii) make acquisitions or merge or consolidate with another entity. These covenants are subject to a number of important exceptions and qualifications. At any time when the senior notes are rated investment grade by each of Moody’s Investors Service, Inc. and Standard & Poor’s Ratings Services and no default or event of default under the indenture has occurred and is continuing, many of these covenants will terminate.

The 5.5% Senior Notes' indenture provides that each of the following is an event of default: (i) default for 30 days in the payment when due of interest on the 5.5% Senior Notes; (ii) default in the payment when due of the principal of, or premium, if any, on the 5.5% Senior Notes; (iii) failure by the Co-Issuers or SMLP to comply with certain covenants relating to mergers and consolidations, change of control or asset sales; (iv) failure by SMLP for 180 days after notice to comply with certain covenants relating to the filing of reports with the SEC; (v) failure by the Co-Issuers or SMLP for 30 days after notice to comply with any of the other agreements in the indenture; (vi) specified defaults under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any indebtedness for money borrowed by SMLP or any of its restricted subsidiaries (or the payment of which is guaranteed by SMLP or any of its restricted subsidiaries); (vii) failure by SMLP or any of its restricted subsidiaries to pay certain final judgments aggregating in excess of $20.0 million; (viii) except as permitted by the indenture, any guarantee of the senior notes shall cease for any reason to be in full force and effect or any guarantor, or any person acting on behalf of any guarantor, shall deny or disaffirm its obligations under its guarantee of the senior notes; and (ix) certain events of bankruptcy, insolvency or reorganization described in the indenture. In the case of an event of default as described in the foregoing clause (ix), all outstanding 5.5% Senior Notes will become due and payable immediately without further action or notice. If any other event of default occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the then outstanding 5.5% Senior Notes may declare all the 5.5% Senior Notes to be due and payable immediately.

As of and during the December 31, 2019, we were in compliance with the financial covenants governing our Senior Notes. There were no defaults or events of default during the year ended December 31, 2019.

11. FINANCIAL INSTRUMENTS

Concentrations of Credit Risk.  Financial instruments that potentially subject us to concentrations of credit risk consist of cash and cash equivalents, restricted cash and accounts receivable. We maintain our cash and cash equivalents and restricted cash in bank deposit accounts that frequently exceed federally insured limits. We have not experienced any losses in such accounts and do not believe we are exposed to any significant risk.

Accounts receivable primarily comprise amounts due for the gathering, compression, treating and processing services we provide to our customers and also the sale of natural gas liquids resulting from our processing services. This industry concentration has the potential to impact our overall exposure to credit risk, either positively or negatively, in that our customers may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of our counterparties and can require letters of credit or other forms of credit assurance for receivables from counterparties that are judged to have substandard credit, unless the credit risk can otherwise be mitigated. Our top five customers or counterparties accounted for 46% of total accounts receivable at December 31, 2019, compared to 39% as of December 31, 2018.

Fair Value.  The carrying amount of cash and cash equivalents, restricted cash, accounts receivable and trade accounts payable reported on the consolidated balance sheet approximates fair value due to their short-term maturities.

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The Deferred Purchase Price Obligation's carrying value is its fair value because carrying value represents the present value of the payment which can be made at any time prior to January 15, 2022. In November 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion (see Note 17 for additional information). 

A summary of the estimated fair value of our debt financial instruments follows.

 

 

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

 

The carrying value on the balance sheet of the Revolving Credit Facility is its fair value due to its floating interest rate. The fair value for the Senior Notes is based on an average of nonbinding broker quotes as of December 31, 2019 and 2018. The use of different market assumptions or valuation methodologies may have a material effect on the estimated fair value of the Senior Notes.

12. PARTNERS' CAPITAL AND MEZZANINE CAPITAL

A rollforward of the number of common limited partner, preferred limited partner and General Partner units follows.

 

 

 

Limited partners

 

 

 

 

 

Series A Preferred Units

 

 

Common

 

 

General

Partner

 

Units, January 1, 2017

 

 

 

 

 

72,111,121

 

 

 

1,471,187

 

Units issued in connection with the November

    2017 Equity Offering

 

 

300,000

 

 

 

 

 

 

 

Net units issued under the SMLP LTIP

 

 

 

 

 

211,327

 

 

 

 

Units issued under ATM program

 

 

 

 

 

763,548

 

 

 

 

General Partner 2% contribution

 

 

 

 

 

 

 

 

19,812

 

Units, December 31, 2017

 

 

300,000

 

 

 

73,085,996

 

 

 

1,490,999

 

Net units issued under the SMLP LTIP

 

 

 

 

 

304,857

 

 

 

 

Units, December 31, 2018

 

 

300,000

 

 

 

73,390,853

 

 

 

1,490,999

 

Conversion of General Partner economic interests

 

 

 

 

 

8,750,000

 

 

 

(1,490,999

)

Net units issued under the SMLP LTIP

 

 

 

 

 

638,335

 

 

 

 

DPPO partial settlement

 

 

 

 

 

10,714,285

 

 

 

 

Units, December 31, 2019

 

 

300,000

 

 

 

93,493,473

 

 

 

 

 

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GP/IDR Exchange.  On March 22, 2019, we cancelled our IDRs and converted our 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units which were issued to SMP Holdings in the Equity Restructuring. These units had a fair value of $84.5 million as of the transaction date (March 22, 2019). As a result of the Equity Restructuring, the general partner units and IDRs were eliminated, are no longer outstanding, and no longer participate in distributions of cash from SMLP. Energy Capital Partners continues to control the non-economic GP interest in SMLP.

Immediately following the Equity Restructuring, SMP Holdings directly owned a 41.8% limited partner interest in SMLP and an affiliate of Energy Capital Partners II, LLC directly owned a 7.2% limited partner interest in SMLP.

Our General Partner held IDRs (through the Equity Restructuring). Our payment of IDRs as reported in distributions to unitholders – General Partner in the statements of partners' capital during the years ended December 31 follow.

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

IDR payments

 

$

2,139

 

 

$

8,535

 

 

$

8,460

 

 

For the purposes of calculating net income attributable to General Partner in the statements of operations and partners' capital, the financial impact of IDRs was recognized in respect of the quarter for which the distributions were declared. For the purposes of calculating distributions to unitholders in the statements of partners' capital and cash flows, IDR payments are recognized in the quarter in which they are paid.

Unit Offerings. In February 2017, we completed a secondary underwritten public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments pursuant to the 2016 SRS. We did not receive any proceeds from this offering.

At-the-market Program.  In February 2017, we executed a new equity distribution agreement and filed a prospectus 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"). During the years ended December 31, 2019 and 2018, there were no transactions under the ATM Program. During the year ended December 31, 2017, we sold 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.

Series A Preferred Units.  In November 2017, we issued 300,000 Series A Fixed-to-Floating Rate Cumulative Redeemable Perpetual Preferred Units (the “Series A 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. 

The Series A Preferred Units rank senior to (i) common units representing limited partner interests in the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that expressly ranks junior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in the Partnership that may be established in the future that is not expressly made senior or subordinated to the Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Series A Preferred Units rank junior to (i) all of the Partnership’s existing and future indebtedness and other liabilities with respect to assets available to satisfy claims against the Partnership and (ii) each other class or series of limited partner interests or other equity securities in the Partnership established in the future that is expressly made senior to the Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period.

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Distributions on the Series A Preferred Units are cumulative and compounding and are payable semi-annually in arrears on the 15th day of each June and December through and including December 15, 2022, and, thereafter, quarterly in arrears on the 15th day of March, June, September and December of each year (each, a “Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Distribution Payment Date, in each case, when, as, and if declared by the General Partner out of legally available funds for such purpose.

The initial distribution rate for the Series A Preferred Units is 9.50% per annum of the $1,000 liquidation preference per Series A Preferred Unit. On and after December 15, 2022, distributions on the Series A Preferred Units will accumulate for each distribution period at a percentage of the liquidation preference equal to the three-month LIBOR plus a spread of 7.43%.

Subsidiary Series A Preferred Units.  In December 2019, we issued 30,000 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 $27.4 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project.

On January 16, 2020, we issued 10,000 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 $9.7 million (after deducting underwriting discounts and offering expenses) to fund capital expenses associated with the Double E Project.

The proceeds associated with the issuance of Subsidiary Series A Preferred Units is classified as restricted cash on the accompanying consolidated balance sheets in accordance with the underlying agreement with TPG Energy Solutions Anthem, L.P. until the related funding is used for the Double E Project.

Accounting for the Subsidiary Series A Preferred Units

These preferred units are considered redeemable securities under GAAP due to the existence of certain redemption provisions that are outside of our control. Therefore, the securities are classified as temporary equity in the mezzanine section of the consolidated balance sheet.

Initial and Subsequent Measurement

We initially recognized these preferred units at the time of issuance in the amount of $27.4 million, their issuance date fair value, net of issuance costs. We will not be required to adjust the carrying amount of these preferred units unless it becomes probable that the units would become redeemable. If events or circumstances indicate that redemption is probable, we would accrete these preferred units to the redemption value over a period of time comprising the date redemption first became probable and the date the units can first be redeemed.

The Subsidiary Series A Preferred Units rank senior to each other class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that expressly ranks junior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event (the “Junior Securities”). The Subsidiary Series A Preferred Units rank equal in all respects with each class or series of limited partner interests or other equity securities in Permian Holdco that may be established in the future that is not expressly made senior or subordinated to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable on a liquidation event (the “Parity Securities”). The Subsidiary Series A Preferred Units rank junior to (i) all of Permian Holdco’s or a subsidiary of Permian Holdco’s future indebtedness and other liabilities with respect to assets available to satisfy claims against Permian Holdco and (ii) each other class or series of limited partner interests or other equity securities in Permian Holdco established in the future that is expressly made senior to the Subsidiary Series A Preferred Units as to the payment of distributions and amounts payable upon a liquidation event. Income is allocated to the Subsidiary Series A Preferred Units in an amount equal to the earned distributions for the respective reporting period.

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Distributions on the Subsidiary Series A Preferred Units are cumulative and compounding and are payable 21 days following the quarterly period ended March, June, September and December of each year (each, a “Series A Distribution Payment Date”) to holders of record as of the close of business on the first business day of the month of the applicable Series A Distribution Payment Date, in each case, when, as, and if declared by Permian Holdco out of legally available funds for such purpose.

The distribution rate for the Subsidiary Series A Preferred Units is 7.00% per annum of the $1,000 liquidation preference per Subsidiary Series A Preferred Unit. A pro-rated initial distribution on the Subsidiary Series A Preferred Units was Paid-in-kind (“PIK”) on January 21, 2020 in an amount equal to 7.00% per Subsidiary Series A Preferred Unit plus 1.00% per annum of the undrawn commitment units.

Noncontrolling Interest.  At December 31, 2017, we recorded Summit Investments' indirect retained ownership interest in OpCo and its subsidiaries as a noncontrolling interest in the consolidated financial statements. In November 2018, a subsidiary of SMLP purchased the remaining 1% ownership interest in OpCo held by a subsidiary of Summit Investments for approximately $10.9 million. As a result of this transaction, other than our investment in Ohio Gathering, our investment in Double E and the Subsidiary Series A Preferred Units at Permian Holdco, our business activities are conducted through wholly owned operating subsidiaries.

Cash Distribution Policy

Our Partnership Agreement requires that we distribute all of our available cash, subject to reserves established by our General Partner, within 45 days after the end of each quarter to unitholders of record on the applicable record date. The amount of distributions paid under our policy is subject to fluctuations based on the amount of cash we generate from our business and the decision to make any distribution is determined by our General Partner, taking into consideration the terms of our Partnership Agreement.

General Partner Interest.  On March 22, 2019, we cancelled our IDRs and converted our 2% economic GP interest to a non-economic GP interest in exchange for 8,750,000 SMLP common units which were issued to SMP Holdings in the Equity Restructuring.

Cash Distributions Paid and Declared.  We paid the following per-unit distributions during the years ended December 31:

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

Per-unit distributions to unitholders

 

$

1.4375

 

 

$

2.300

 

 

$

2.300

 

 

On January 29, 2020, the Board of Directors declared a distribution of $0.125 per unit for the quarterly period ended December 31, 2019. This distribution, which totaled $11.7 million, was paid on February 14, 2020 to unitholders of record at the close of business on February 7, 2020.

With respect to our Subsidiary Series A Preferred Units relating to the fourth quarter of 2019, we declared a payment-in-kind ("PIK") of the quarterly distribution, which resulted in the pro-rated issuance of 47 Subsidiary Series A Preferred Units. This PIK amount equates to a pro-rated distribution of $1.5556 per Subsidiary Series A Preferred Unit for the fourth quarter in 2019, or $70 on a full year annualized basis.

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13. EARNINGS PER UNIT

The following table details the components of EPU.

 

 

 

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

 

$

(369,845

)

 

$

32,799

 

 

$

75,485

 

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

 

$

(398,403

)

 

$

4,299

 

 

$

71,922

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Denominator for basic and diluted EPU:

 

 

 

 

 

 

 

 

 

 

 

 

Weighted-average common units outstanding – basic

 

 

82,365

 

 

 

73,304

 

 

 

72,705

 

Effect of nonvested phantom units

 

 

 

 

 

311

 

 

 

342

 

Weighted-average common units outstanding – diluted

 

 

82,365

 

 

 

73,615

 

 

 

73,047

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(Loss) earnings per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

Common unit – basic

 

$

(4.84

)

 

$

0.06

 

 

$

0.99

 

Common unit – diluted

 

$

(4.84

)

 

$

0.06

 

 

$

0.98

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Nonvested anti-dilutive phantom units excluded from the

    calculation of diluted EPU

 

 

175

 

 

 

2

 

 

 

42

 

 

14. UNIT-BASED AND NONCASH COMPENSATION

 

SMLP Long-Term Incentive Plan. The SMLP LTIP provides for equity awards to eligible officers, employees, consultants and directors of our General Partner and its affiliates, thereby linking the recipients' compensation directly to SMLP’s performance. The SMLP LTIP is administered by our General Partner's Board of Directors, though such administration function may be delegated to a committee appointed by the board. A total of 5.0 million common units was reserved for issuance pursuant to and in accordance with the SMLP LTIP. As of December 31, 2019, approximately 1.3 million common units remained available for future issuance.

The SMLP LTIP provides for the granting, from time to time, of unit-based awards, including common units, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Grants are made at the discretion of the Board of Directors or Compensation Committee of our General Partner. The administrator of the SMLP LTIP may make grants under the SMLP LTIP that contain such terms, consistent with the SMLP LTIP, as the administrator may determine are appropriate, including vesting conditions. The administrator of the SMLP LTIP may, in its discretion, base vesting on the grantee's completion of a period of service or upon the achievement of specified financial objectives or other criteria or upon a change of control (as defined in the SMLP LTIP) or as otherwise described in an award agreement. Termination of employment prior to vesting will result in forfeiture of the awards, except in limited circumstances as described in the plan documents. Units that are canceled or forfeited will be available for delivery pursuant to other awards.  

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The following table presents phantom unit activity:

 

 

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

 

A phantom unit is a notional unit that entitles the grantee to receive a common unit upon the vesting of the phantom unit or on a deferred basis upon specified future dates or events or, in the discretion of the administrator, cash equal to the fair market value of a common unit. Distribution equivalent rights for each phantom unit provide for a lump sum cash amount equal to the accrued distributions from the grant date to be paid in cash upon the vesting date.

Phantom units granted to date generally vest ratably over a three-year period. Grant date fair value is determined based on the closing price of our common units on the date of grant multiplied by the number of phantom units awarded to the grantee. Forfeitures are recorded as incurred. Holders of all phantom units granted to date are entitled to receive distribution equivalent rights for each phantom unit, providing for a lump sum cash amount equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Upon vesting, phantom unit awards may be settled, at our discretion, in cash and/or common units, but the current intention is to settle all phantom unit awards with common units.

The intrinsic value of phantom units that vested during the years ended December 31, follows.

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Intrinsic value of vested LTIP awards

 

$

5,940

 

 

$

5,393

 

 

$

6,657

 

As of December 31, 2019, the unrecognized unit-based compensation related to the SMLP LTIP was $8.5 million.  Incremental unit-based compensation will be recorded over the remaining weighted-average vesting period of approximately 1.6 years.

Unit-based compensation recognized in general and administrative expense related to awards under the SMLP LTIP follows.

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

SMLP LTIP unit-based compensation

 

$

8,171

 

 

$

8,328

 

 

$

7,951

 

 

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15. RELATED-PARTY TRANSACTIONS

Acquisitions. See Notes 1 and 17.

Reimbursement of Expenses from General Partner.  Our General Partner and its affiliates do not receive a management fee or other compensation in connection with the management of our business, but will be reimbursed for expenses incurred on our behalf. Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. The "Due to affiliate" line item on the consolidated balance sheet represents the payables to our General Partner for expenses incurred by it and paid on our behalf.

Expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were as follows:

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Operation and maintenance expense

 

$

28,643

 

 

$

29,061

 

 

$

27,450

 

General and administrative expense

 

 

32,222

 

 

 

30,119

 

 

 

30,899

 

In February 2017, SMP Holdings sold 4,000,000 common units representing limited partner interests in SMLP at a price to the public of $24.00 per common unit. Consistent with our obligations under the Partnership Agreement, we paid all costs and expenses of the secondary offering (other than underwriting discounts and fees and expenses of counsel and advisors to SMP Holdings in the sale). We did not receive any of the proceeds from the secondary offering.

16. LEASES, COMMITMENTS AND CONTINGENCIES

Leases.  We account for leases in accordance with Topic 842, which we adopted on January 1, 2019, using the modified retrospective method. Under the modified retrospective method, the comparative information is not adjusted and is reported under the accounting standards in effect for those periods. See Note 2 for further discussion of the adoption.

We and Summit Investments lease certain office space and equipment under operating leases. We lease office space for our corporate headquarters as well as for corporate offices in Dallas, Denver and Atlanta and offices in and around our gathering systems for terms of between 3 and 10 years. We lease the office space to limit exposure to risks related to ownership, such as fluctuations in real estate prices. In addition, we lease equipment primarily to support our operations in response to the needs of our gathering systems for terms of between 3 and 4 years. We and Summit Investments also lease vehicles under finance leases to support our operations in response to the needs of our gathering systems for a term of 3 years. We only lease from reputable companies and our leased assets are not specialized in our industry.

Some of our leases are subject to annual escalations relating to the Consumer Price Index (“CPI”). While lease liabilities are not remeasured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred.

We have options to extend the lease term of certain office space in Texas, Colorado and West Virginia. The beginning of the noncancelable lease period for these leases ranged from 2014 to 2018 and the lease period ends between 2020 and 2028. These lease agreements contain between one and three options to renew the lease for a period of between two and five years. As of December 31, 2019, the exercise of the renewal options for these leases are not reasonably certain and, as a result, the payments associated with these renewals are not included in the measurement of the lease liability and ROU asset.

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We also have options to extend the lease term of certain compression equipment used at the Summit Utica gathering system. The beginning of the noncancelable lease period for these leases was 2017 and the lease period ends in 2020. Upon expiration of the noncancelable lease period, we have the option to renew the leases on a month-to-month basis; we therefore have not included any amounts attributable to renewals in the measurement.

Our leases do not contain residual value guarantees.

In accordance with the provisions in our Revolving Credit Facility, our aggregate finance lease obligations cannot exceed $50 million in any period of twelve consecutive calendar months during the life of such leases.

In November 2019, we entered into a sublease agreement with a third party to sublease corporate office space in Houston, Texas. The noncancelable sublease period begins in 2020 and the sublease period ends in 2025. The sublease agreement contains one option to renew the lease for five years. We moved our corporate headquarters to the Houston office on March 2, 2020. Our future minimum sublease payments are approximately $1.2 million.

In March 2019, we entered into an agreement with a third party vendor to construct a transmission line to deliver electric power to the new 60 MMcf/d processing plant in the DJ Basin. The project is expected to cost approximately $7.8 million and we made an up-front payment of $3.0 million, which is included in the Property, plant and equipment, net caption on the consolidated balance sheet. During the second quarter of 2019, we exercised an option to increase the capacity of the transmission line for an additional cost of $4.3 million and we issued an irrevocable standby letter of credit payable to the vendor with an initial term of one year totaling $9.1 million, which reflects the expected remaining cost of the project. The letter of credit will automatically renew for successive twelve month periods following the initial term, subject to certain adjustments. Once construction is complete, the letter of credit will be adjusted to reflect the final construction cost. We determined the contract contained a lease based on the right to use the constructed transmission line to power the processing plant in the DJ Basin. The project is expected to be completed and the commencement date of the ROU asset will be on or before January 2021.

Our significant assumptions or judgments include the determination of whether a contract contains a lease and the discount rate used in our lease liabilities.

The rate implicit in our lease contracts is not readily determinable. In determining the discount rate used in our lease liabilities, we analyzed certain factors in our incremental borrowing rate, including collateral assumptions and the term used. Our incremental borrowing rate on the Revolving Credit Facility was 4.55% at December 31, 2019, which reflects the fixed rate at which we could borrow a similar amount, for a similar term and with similar collateral as in the lease contracts at the commencement date.

We adopted the following practical expedients in Topic 842 for all asset classes, which included (i) not being required to reassess whether any expired or existing contracts are or contain leases; (ii) not being required to reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will be classified as finance leases); (iii) not being required to reassess initial direct costs for any existing leases; (iv) not recognizing ROU assets and lease liabilities that arise from short-term leases of twelve months or less for any class of underlying asset; (v) not allocating consideration in a contract between lease and nonlease (e.g., maintenance services) components for our leased office space and equipment; and (vi) not evaluating existing or expired land easements that were not previously accounted for as leases under Topic 840.

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ROU assets (included in the Property, plant and equipment, net caption on our consolidated balance sheet) and lease liabilities (included in the Other current liabilities and Other noncurrent liabilities captions on our consolidated balance sheet) follow:

 

 

 

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

 

 

Lease cost and Other information follow:

 

 

 

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)

 

 

3,159

 

 

 

$

4,820

 

 

 

 

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

%

 

We recognize total lease expense incurred or allocated to us in general and administrative expenses. Lease expense related to operating leases, including lease expense incurred on our behalf and allocated to us, was as follows: 

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

 

2017

 

 

 

(In thousands)

 

Lease expense

 

$

3,851

 

 

$

3,928

 

 

$

3,772

 

 

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Future minimum lease payments due under noncancelable leases at December 31, 2019, were as follows

 

 

 

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

 

 

Future minimum lease payments due under noncancelable operating leases (under ASC 840) at December 31, 2018, were as follows:

 

 

 

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

 

 

Future payments due under finance leases (under ASC 840) at December 31, 2018, were as follows:

 

 

 

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

 

 

Environmental Matters.  Although we believe that we are in material compliance with applicable environmental regulations, the risk of environmental remediation costs and liabilities are inherent in pipeline ownership and operation. Furthermore, we can provide no assurances that significant environmental remediation costs and liabilities will not be incurred by the Partnership in the future. We are currently not aware of any material contingent liabilities that exist with respect to environmental matters, except as noted below.

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In 2015, Summit Investments learned of the rupture of a four-inch produced water gathering pipeline on the Meadowlark Midstream system near Williston, North Dakota. The incident, which was covered by Summit Investments' insurance policies, was subject to maximum coverage of $25.0 million from its pollution liability insurance policy and $200.0 million from its property and business interruption insurance policy. Summit Investments exhausted the $25.0 million pollution liability policy in 2015. We submitted property and business interruption claim requests to the insurers and reached a settlement in January 2017. In connection therewith, we recognized $2.6 million of business interruption recoveries and $0.4 million of property recoveries.

A rollforward of the aggregate accrued environmental remediation liabilities follows.

 

 

 

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

 

 

As of December 31, 2019, we have recognized (i) a current liability for remediation effort expenditures expected to be incurred within the next 12 months and (ii) a noncurrent liability for estimated remediation expenditures and fines expected to be incurred subsequent to December 31, 2020. Each of these amounts represent our best estimate for costs expected to be incurred. Neither of these amounts has been discounted to its present value.

While we cannot predict the ultimate outcome of this matter with certainty for Summit Investments or Meadowlark Midstream, especially as it relates to any material liability as a result of any governmental proceeding related to the incident, we believe at this time that it is unlikely that SMLP or its General Partner will be subject to any material liability as a result of any governmental proceeding related to the rupture.

Legal Proceedings.  The Partnership is involved in various litigation and administrative proceedings arising in the normal course of business. In the opinion of management, any liabilities that may result from these claims or those arising in the normal course of business would not individually or in the aggregate have a material adverse effect on the Partnership's financial position or results of operations.  

 

17. DISPOSITIONS, DROP DOWN TRANSACTIONS AND RESTRUCTURING

Red Rock Gathering Asset Disposition.  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, subject to adjustments as provided in the Red Rock PSA (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.

Tioga Midstream Disposition.  In February 2019, Tioga Midstream, LLC, a subsidiary of SMLP, and certain affiliates of SMLP (collectively, “the Tioga Parties”) entered into two Purchase and Sale Agreements (the “Tioga PSAs”) with Hess Infrastructure Partners LP and Hess North Dakota Pipelines LLC (collectively, “Hess Infrastructure”), pursuant to which the Tioga Parties agreed to sell the Tioga Midstream system to Hess Infrastructure for a combined cash purchase price of $90 million, subject to adjustments as provided in the Tioga PSAs (the “Tioga Midstream Sale”). On March 22, 2019, the Tioga Parties closed the Tioga Midstream Sale 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 through March 22, 2019.

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2016 Drop Down.  In 2016, SMLP acquired a controlling interest in OpCo, the entity which owns the 2016 Drop Down Assets. These assets include certain natural gas, crude oil and produced water gathering systems located in the Utica Shale, the Williston Basin and the DJ Basin, as well as ownership interests in Ohio Gathering.

The net consideration paid and recognized in connection with the 2016 Drop Down (i) consisted of a cash payment to SMP Holdings of $360.0 million funded with borrowings under our Revolving Credit Facility and a $0.6 million working capital adjustment received in June 2016 (the “Initial Payment”) and (ii) includes the Deferred Purchase Price Obligation payment due in 2020.

In March 2019, the Partnership amended the Contribution Agreement related to the 2016 Drop Down and fixed the Remaining Consideration at $303.5 million, with such amount to be paid by the Partnership in one or more payments over the period from March 1, 2020 through December 31, 2020, in (i) cash, (ii) the Partnership’s common units or (iii) a combination of cash and the Partnership’s common units, at the discretion of the Partnership. At least 50% of the Remaining Consideration must be paid on or before June 30, 2020 and interest will accrue at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020.

On November 7, 2019, we and SMP Holdings entered into a second amendment (the “Second Amendment”) to the Contribution Agreement between us and SMP Holdings dated February 25, 2016, as amended. On November 15, 2019, we made a cash payment of $51.75 million and issued 10,714,285 common units to SMP Holdings (the “November 2019 Prepayment”). In addition, the parties reduced the Remaining Consideration due to SMP Holdings by $19.25 million. Following the November 2019 Prepayment, the Remaining Consideration is $180.75 million. The parties also extended the final date by which we are obligated to deliver the Remaining Consideration to January 15, 2022. The Remaining Consideration remains payable to SMP Holdings in (i) cash, (ii) our common units or (iii) a combination of cash and our common units, and interest continues to accrue (and is payable quarterly in cash) at a rate of 8% per annum on any portion of the Remaining Consideration that remains unpaid after March 31, 2020. The form(s) of Remaining Consideration to be delivered by us to SMP Holdings continue to be determinable by us in our sole discretion.

The present value of the Deferred Purchase Price Obligation is reflected as a liability on our balance sheet until paid. As of December 31, 2019, the Remaining Consideration, which reflects the net present value of the $180.75 million Deferred Purchase Price Obligation, was $178.5 million on the consolidated balance sheet using a discount rate of 5.25%.

Restructuring Activities.  In 2019, our management approved and initiated a plan to restructure our operations resulting in certain management, facility and organizational changes. During the year ended December 31, 2019, we expensed costs of approximately $5.0 million associated with restructuring activities. These activities consisted primarily of employee-related costs and consulting costs in support of the project. These costs are included within the General and administrative caption on the consolidated statement of operations.

As of December 31, 2019, the components of our restructuring plan are as follows:

 

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.

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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.

18. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

The Senior Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by SMLP and the Guarantor Subsidiaries (see Note 10).

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 December 2019, we executed the third amendment to the third amended and restated credit agreement that, among other things, designated Permian Holdco and Summit Permian Transmission as unrestricted subsidiaries under the Revolving Credit Facility. Prior to this amendment, Summit Permian Transmission did not have any assets or operations. In December 2019, we executed a partial release agreement that designated the Non-Guarantor Subsidiaries as unrestricted subsidiaries under the Senior Notes. As a result of these transactions, all prior periods presented have been recast to reflect this change.

The following supplemental condensed consolidating financial information reflects SMLP's separate accounts, the combined accounts of the Co-Issuers, the combined accounts of the Guarantor Subsidiaries, the combined accounts of the Non-Guarantor Subsidiaries and the consolidating adjustments for the dates and periods indicated. For purposes of the following consolidating information each of SMLP and the Co-Issuers account for their subsidiary investments, if any, under the equity method of accounting.

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Condensed Consolidating Balance Sheet. Balance sheets as of December 31, 2019 and 2018 follow.

 

 

 

December 31, 2019

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

118

 

 

$

611

 

 

$

4,110

 

 

$

109

 

 

$

 

 

$

4,948

 

Restricted cash

 

 

 

 

 

 

 

 

 

 

 

27,392

 

 

 

 

 

 

27,392

 

Accounts receivable

 

 

69

 

 

 

 

 

 

102,049

 

 

 

 

 

 

 

 

 

102,118

 

Other current assets

 

 

2,124

 

 

 

 

 

 

2,894

 

 

 

 

 

 

 

 

 

5,018

 

Due from affiliate

 

 

 

 

 

36,300

 

 

 

776,552

 

 

 

 

 

 

(812,852

)

 

 

 

Total current assets

 

 

2,311

 

 

 

36,911

 

 

 

885,605

 

 

 

27,501

 

 

 

(812,852

)

 

 

139,476

 

Property, plant and equipment, net

 

 

6,420

 

 

 

 

 

 

1,875,558

 

 

 

 

 

 

273

 

 

 

1,882,251

 

Intangible assets, net

 

 

 

 

 

 

 

 

232,278

 

 

 

 

 

 

 

 

 

232,278

 

Investment in equity method

  investees

 

 

 

 

 

 

 

 

275,000

 

 

 

35,002

 

 

 

(274

)

 

 

309,728

 

Other noncurrent assets

 

 

3,152

 

 

 

6,167

 

 

 

29

 

 

 

370

 

 

 

 

 

 

9,718

 

Investment in subsidiaries

 

 

1,758,547

 

 

 

3,198,079

 

 

 

 

 

 

 

 

 

(4,956,626

)

 

 

 

Total assets

 

$

1,770,430

 

 

$

3,241,157

 

 

$

3,268,470

 

 

$

62,873

 

 

$

(5,769,479

)

 

$

2,573,451

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

657

 

 

$

 

 

$

23,758

 

 

$

 

 

$

 

 

$

24,415

 

Accrued expenses

 

 

1,649

 

 

 

 

 

 

9,536

 

 

 

297

 

 

 

 

 

 

11,482

 

Due to affiliate

 

 

777,077

 

 

 

 

 

 

 

 

 

 

 

 

(776,766

)

 

 

311

 

Deferred revenue

 

 

 

 

 

 

 

 

13,493

 

 

 

 

 

 

 

 

 

13,493

 

Ad valorem taxes payable

 

 

14

 

 

 

 

 

 

8,463

 

 

 

 

 

 

 

 

 

 

8,477

 

Accrued interest

 

 

 

 

 

12,311

 

 

 

 

 

 

 

 

 

 

 

 

12,311

 

Accrued environmental remediation

 

 

 

 

 

 

 

 

1,725

 

 

 

 

 

 

 

 

 

1,725

 

Other current liabilities

 

 

7,342

 

 

 

 

 

 

4,591

 

 

 

 

 

 

 

 

 

 

11,933

 

Total current liabilities

 

 

786,739

 

 

 

12,311

 

 

 

61,566

 

 

 

297

 

 

 

(776,766

)

 

 

84,147

 

Long-term debt

 

 

 

 

 

1,470,299

 

 

 

 

 

 

 

 

 

 

 

 

1,470,299

 

Noncurrent Deferred Purchase Price

  Obligation

 

 

178,453

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

178,453

 

Noncurrent deferred revenue

 

 

 

 

 

 

 

 

38,709

 

 

 

 

 

 

 

 

 

38,709

 

Noncurrent accrued environmental

  remediation

 

 

 

 

 

 

 

 

2,926

 

 

 

 

 

 

 

 

 

2,926

 

Other noncurrent liabilities

 

 

5,635

 

 

 

 

 

 

2,316

 

 

 

 

 

 

 

 

 

7,951

 

Total liabilities

 

 

970,827

 

 

 

1,482,610

 

 

 

105,517

 

 

 

297

 

 

 

(776,766

)

 

 

1,782,485

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total mezzanine capital

 

 

 

 

 

 

 

 

 

 

 

27,450

 

 

 

 

 

 

27,450

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total partners' capital

 

 

799,603

 

 

 

1,758,547

 

 

 

3,162,953

 

 

 

35,126

 

 

 

(4,992,713

)

 

 

763,516

 

Total liabilities, mezzanine capital

    and partners' capital

 

$

1,770,430

 

 

$

3,241,157

 

 

$

3,268,470

 

 

$

62,873

 

 

$

(5,769,479

)

 

$

2,573,451

 

 

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December 31, 2018

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Assets

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and cash equivalents

 

$

185

 

 

$

230

 

 

$

3,930

 

 

$

 

 

$

 

 

$

4,345

 

Accounts receivable

 

 

321

 

 

 

 

 

 

97,615

 

 

 

 

 

 

 

 

 

97,936

 

Other current assets

 

 

1,179

 

 

 

 

 

 

2,792

 

 

 

 

 

 

 

 

 

3,971

 

Due from affiliate

 

 

 

 

 

 

 

 

593,384

 

 

 

 

 

 

(593,384

)

 

 

 

Total current assets

 

 

1,685

 

 

 

230

 

 

 

697,721

 

 

 

 

 

 

(593,384

)

 

 

106,252

 

Property, plant and equipment, net

 

 

5,813

 

 

 

 

 

 

1,948,280

 

 

 

9,620

 

 

 

 

 

 

1,963,713

 

Intangible assets, net

 

 

 

 

 

 

 

 

273,416

 

 

 

 

 

 

 

 

 

273,416

 

Goodwill

 

 

 

 

 

 

 

 

16,211

 

 

 

 

 

 

 

 

 

16,211

 

Investment in equity method

  investees

 

 

 

 

 

 

 

 

649,250

 

 

 

 

 

 

 

 

 

649,250

 

Other noncurrent assets

 

 

3,183

 

 

 

8,511

 

 

 

26

 

 

 

 

 

 

 

 

 

11,720

 

Investment in subsidiaries

 

 

2,096,717

 

 

 

3,461,921

 

 

 

 

 

 

 

 

 

(5,558,638

)

 

 

 

Total assets

 

$

2,107,398

 

 

$

3,470,662

 

 

$

3,584,904

 

 

$

9,620

 

 

$

(6,152,022

)

 

$

3,020,562

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Liabilities and Partners' Capital

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Trade accounts payable

 

$

275

 

 

$

 

 

$

35,831

 

 

$

2,308

 

 

$

 

 

$

38,414

 

Accrued expenses

 

 

1,106

 

 

 

 

 

 

20,857

 

 

 

 

 

 

 

 

 

21,963

 

Due to affiliate

 

 

482,384

 

 

 

103,928

 

 

 

 

 

 

 

 

 

(586,072

)

 

 

240

 

Deferred revenue

 

 

 

 

 

 

 

 

11,467

 

 

 

 

 

 

 

 

 

11,467

 

Ad valorem taxes payable

 

 

14

 

 

 

 

 

 

10,536

 

 

 

 

 

 

 

 

 

10,550

 

Accrued interest

 

 

 

 

 

12,286

 

 

 

 

 

 

 

 

 

 

 

 

12,286

 

Accrued environmental remediation

 

 

 

 

 

 

 

 

2,487

 

 

 

 

 

 

 

 

 

2,487

 

Other current liabilities

 

 

7,306

 

 

 

 

 

 

5,339

 

 

 

 

 

 

 

 

 

12,645

 

Total current liabilities

 

 

491,085

 

 

 

116,214

 

 

 

86,517

 

 

 

2,308

 

 

 

(586,072

)

 

 

110,052

 

Long-term debt

 

 

 

 

 

1,257,731

 

 

 

 

 

 

 

 

 

 

 

 

1,257,731

 

Noncurrent Deferred Purchase Price

    Obligation

 

 

383,934

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

383,934

 

Noncurrent deferred revenue

 

 

 

 

 

 

 

 

39,504

 

 

 

 

 

 

 

 

 

39,504

 

Noncurrent accrued environmental

    remediation

 

 

 

 

 

 

 

 

3,149

 

 

 

 

 

 

 

 

 

3,149

 

Other noncurrent liabilities

 

 

3,843

 

 

 

 

 

 

1,125

 

 

 

 

 

 

 

 

 

4,968

 

Total liabilities

 

 

878,862

 

 

 

1,373,945

 

 

 

130,295

 

 

 

2,308

 

 

 

(586,072

)

 

 

1,799,338

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total partners' capital

 

 

1,228,536

 

 

 

2,096,717

 

 

 

3,454,609

 

 

 

7,312

 

 

 

(5,565,950

)

 

 

1,221,224

 

Total liabilities partners' capital

 

$

2,107,398

 

 

$

3,470,662

 

 

$

3,584,904

 

 

$

9,620

 

 

$

(6,152,022

)

 

$

3,020,562

 

 

Condensed Consolidating Statement of Operations. For the purposes of the following condensed consolidating statements of operations, we allocate general and administrative expenses recognized at the SMLP parent to the Guarantor Subsidiaries and Non-Guarantor Subsidiaries to reflect what those entities' results would have been had they operated on a stand-alone basis. Statements of operation for the years ended December 31, 2019, 2018 and 2017 follow.

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Year ended December 31, 2019

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

 

 

$

 

 

$

326,747

 

 

 

 

 

 

$

 

 

$

326,747

 

Natural gas, NGLs and condensate

    sales

 

 

 

 

 

 

 

 

86,994

 

 

 

 

 

 

 

 

 

86,994

 

Other revenues

 

 

 

 

 

 

 

 

29,787

 

 

 

 

 

 

 

 

 

 

29,787

 

Total revenues

 

 

 

 

 

 

 

 

443,528

 

 

 

 

 

 

 

 

 

443,528

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

 

 

 

 

 

 

63,438

 

 

 

 

 

 

 

 

 

63,438

 

Operation and maintenance

 

 

 

 

 

 

 

 

97,587

 

 

 

 

 

 

 

 

 

97,587

 

General and administrative

 

 

 

 

 

 

 

 

54,139

 

 

 

 

 

 

 

 

 

54,139

 

Depreciation and amortization

 

 

2,604

 

 

 

 

 

 

107,602

 

 

 

 

 

 

 

 

 

110,206

 

Transaction costs

 

 

1,788

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,788

 

Loss (gain) on asset sales, net

 

 

9

 

 

 

 

 

 

(1,545

)

 

 

 

 

 

 

 

 

(1,536

)

Long-lived asset impairment

 

 

 

 

 

 

 

 

60,507

 

 

 

 

 

 

 

 

 

60,507

 

Goodwill impairment

 

 

 

 

 

 

 

 

16,211

 

 

 

 

 

 

 

 

 

16,211

 

Total costs and expenses

 

 

4,401

 

 

 

 

 

 

397,939

 

 

 

 

 

 

 

 

 

402,340

 

Other income

 

 

451

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

451

 

Interest expense

 

 

 

 

 

(74,327

)

 

 

(102

)

 

 

 

 

 

 

 

 

(74,429

)

Deferred Purchase Price Obligation

 

 

1,982

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

1,982

 

(Loss) income before income

    taxes and loss from equity

    method investees

 

 

(1,968

)

 

 

(74,327

)

 

 

45,487

 

 

 

 

 

 

 

 

 

(30,808

)

Income tax expense

 

 

(1,174

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1,174

)

Loss from equity method

    investees

 

 

 

 

 

 

 

 

(336,950

)

 

 

(901

)

 

 

 

 

 

(337,851

)

Equity in earnings of consolidated

    subsidiaries

 

 

(366,691

)

 

 

(292,364

)

 

 

 

 

 

 

 

 

659,055

 

 

 

 

Net (loss) income

 

$

(369,833

)

 

$

(366,691

)

 

$

(291,463

)

 

$

(901

)

 

$

659,055

 

 

$

(369,833

)

 

154


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Year ended December 31, 2018

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

 

 

$

 

 

$

344,616

 

 

$

 

 

$

 

 

$

344,616

 

Natural gas, NGLs and condensate

    sales

 

 

 

 

 

 

 

 

134,834

 

 

 

 

 

 

 

 

 

134,834

 

Other revenues

 

 

 

 

 

 

 

 

27,203

 

 

 

 

 

 

 

 

 

27,203

 

Total revenues

 

 

 

 

 

 

 

 

506,653

 

 

 

 

 

 

 

 

 

506,653

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

 

 

 

 

 

 

107,661

 

 

 

 

 

 

 

 

 

107,661

 

Operation and maintenance

 

 

 

 

 

 

 

 

96,878

 

 

 

 

 

 

 

 

 

96,878

 

General and administrative

 

 

 

 

 

 

 

 

52,877

 

 

 

 

 

 

 

 

 

52,877

 

Depreciation and amortization

 

 

1,743

 

 

 

 

 

 

105,357

 

 

 

 

 

 

 

 

 

107,100

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

7,186

 

 

 

 

 

 

 

 

 

7,186

 

Total costs and expenses

 

 

1,743

 

 

 

 

 

 

369,959

 

 

 

 

 

 

 

 

 

371,702

 

Other income

 

 

(169

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(169

)

Interest expense

 

 

 

 

 

(60,442

)

 

 

(93

)

 

 

 

 

 

 

 

 

(60,535

)

Deferred Purchase Price Obligation

 

 

(20,975

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(20,975

)

Income (loss) before income

    taxes and loss from equity

    method investees

 

 

(22,887

)

 

 

(60,442

)

 

 

136,601

 

 

 

 

 

 

 

 

 

53,272

 

Income tax expense

 

 

(33

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(33

)

Loss from equity method

    investees

 

 

 

 

 

 

 

 

(10,888

)

 

 

 

 

 

 

 

 

(10,888

)

Equity in earnings of consolidated

    subsidiaries

 

 

65,271

 

 

 

125,713

 

 

 

 

 

 

 

 

 

(190,984

)

 

 

 

Net income

 

$

42,351

 

 

$

65,271

 

 

$

125,713

 

 

$

 

 

$

(190,984

)

 

$

42,351

 

 

155


Table of Contents

 

 

 

 

Year ended December 31, 2017

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Revenues:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gathering services and related fees

 

$

 

 

$

 

 

$

394,427

 

 

$

 

 

$

 

 

$

394,427

 

Natural gas, NGLs and condensate

    sales

 

 

 

 

 

 

 

 

68,459

 

 

 

 

 

 

 

 

 

68,459

 

Other revenues

 

 

 

 

 

 

 

 

25,855

 

 

 

 

 

 

 

 

 

25,855

 

Total revenues

 

 

 

 

 

 

 

 

488,741

 

 

 

 

 

 

 

 

 

488,741

 

Costs and expenses:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cost of natural gas and NGLs

 

 

 

 

 

 

 

 

57,237

 

 

 

 

 

 

 

 

 

57,237

 

Operation and maintenance

 

 

 

 

 

 

 

 

93,882

 

 

 

 

 

 

 

 

 

93,882

 

General and administrative

 

 

 

 

 

 

 

 

54,681

 

 

 

 

 

 

 

 

 

54,681

 

Depreciation and amortization

 

 

1,101

 

 

 

 

 

 

114,374

 

 

 

 

 

 

 

 

 

115,475

 

Transaction costs

 

 

73

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

73

 

Gain on asset sales, net

 

 

 

 

 

 

 

 

527

 

 

 

 

 

 

 

 

 

527

 

Long-lived asset impairment

 

 

 

 

 

 

 

 

188,702

 

 

 

 

 

 

 

 

 

188,702

 

Total costs and expenses

 

 

1,174

 

 

 

 

 

 

509,403

 

 

 

 

 

 

 

 

 

510,577

 

Other income

 

 

298

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

298

 

Interest expense

 

 

 

 

 

(68,080

)

 

 

(51

)

 

 

 

 

 

 

 

 

(68,131

)

Early extinguishment of debt

 

 

 

 

 

(22,039

)

 

 

 

 

 

 

 

 

 

 

 

(22,039

)

Deferred Purchase Price Obligation

 

 

200,322

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

200,322

 

Loss before income

    taxes and loss from equity

    method investees

 

 

199,446

 

 

 

(90,119

)

 

 

(20,713

)

 

 

 

 

 

 

 

 

88,614

 

Income tax expense

 

 

(341

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(341

)

Loss from equity method

    investees

 

 

 

 

 

 

 

 

(2,223

)

 

 

 

 

 

 

 

 

(2,223

)

Equity in loss of

    consolidated subsidiaries

 

 

(113,055

)

 

 

(22,936

)

 

 

 

 

 

 

 

 

135,991

 

 

 

 

Net loss

 

$

86,050

 

 

$

(113,055

)

 

$

(22,936

)

 

$

 

 

$

135,991

 

 

$

86,050

 

 

156


Table of Contents

 

Condensed Consolidating Statement of Cash Flows. Statement of cash flows for the years ended December 31, 2019, 2018 and 2017 follow.

 

 

 

Year ended December 31, 2019

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Cash flows from operating

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in)

    operating activities

 

$

5,811

 

 

$

(69,891

)

 

$

246,492

 

 

$

(75

)

 

$

 

 

$

182,337

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

 

(1,323

)

 

 

 

 

 

(163,379

)

 

 

(17,589

)

 

 

 

 

 

(182,291

)

Proceeds from asset sales

 

 

 

 

 

 

 

 

102,111

 

 

 

 

 

 

 

 

 

102,111

 

Distributions from equity method

    investment

 

 

 

 

 

 

 

 

 

 

 

7,313

 

 

 

 

 

 

7,313

 

Investment in equity method

    investee

 

 

 

 

 

 

 

 

 

 

 

(18,316

)

 

 

 

 

 

(18,316

)

Other, net

 

 

314

 

 

 

 

 

 

(1

)

 

 

 

 

 

 

 

 

313

 

Advances to affiliates

 

 

(28,776

)

 

 

(140,229

)

 

 

(183,170

)

 

 

 

 

 

352,175

 

 

 

 

Net cash (used in)

    provided by investing

    activities

 

 

(29,785

)

 

 

(140,229

)

 

 

(244,439

)

 

 

(28,592

)

 

 

352,175

 

 

 

(90,870

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to unitholders

 

 

(116,624

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(116,624

)

Distributions to Series A Preferred

    unitholders

 

 

(28,500

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(28,500

)

Borrowings under Revolving Credit

    Facility

 

 

 

 

 

369,000

 

 

 

 

 

 

 

 

 

 

 

 

369,000

 

Repayments under Revolving Credit

    Facility

 

 

 

 

 

(158,000

)

 

 

 

 

 

 

 

 

 

 

 

(158,000

)

Repayment of Deferred Purchase

    Price Obligation

 

 

(151,750

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(151,750

)

Debt issuance costs

 

 

 

 

 

(499

)

 

 

 

 

 

 

 

 

 

 

 

(499

)

Proceeds from the issuance of Series

    A preferred units, net of costs

 

 

 

 

 

 

 

 

 

 

 

27,392

 

 

 

 

 

 

27,392

 

Other, net

 

 

(2,618

)

 

 

 

 

 

(1,873

)

 

 

 

 

 

 

 

 

 

(4,491

)

Advances from affiliates

 

 

323,399

 

 

 

 

 

 

 

 

 

28,776

 

 

 

(352,175

)

 

 

 

Net cash (used in) provided by

    financing activities

 

 

23,907

 

 

 

210,501

 

 

 

(1,873

)

 

 

56,168

 

 

 

(352,175

)

 

 

(63,472

)

Net change in cash, cash

    equivalents and restricted

    cash

 

 

(67

)

 

 

381

 

 

 

180

 

 

 

27,501

 

 

 

 

 

 

27,995

 

Cash, cash equivalents and

    restricted cash, beginning

    of period

 

 

185

 

 

 

230

 

 

 

3,930

 

 

 

 

 

 

 

 

 

4,345

 

Cash, cash equivalents and

    restricted cash, end of

    period

 

$

118

 

 

$

611

 

 

$

4,110

 

 

$

27,501

 

 

$

 

 

$

32,340

 

 

157


Table of Contents

 

 

 

 

Year ended December 31, 2018

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Cash flows from operating

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in)

    operating activities

 

$

7,470

 

 

$

(56,181

)

 

$

276,640

 

 

$

 

 

$

 

 

$

227,929

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

 

(3,323

)

 

 

 

 

 

(189,951

)

 

 

(7,312

)

 

 

 

 

 

(200,586

)

Proceeds from asset sales

 

 

 

 

 

 

 

 

496

 

 

 

 

 

 

 

 

 

496

 

Contributions to equity method

    investees

 

 

 

 

 

 

 

 

(4,924

)

 

 

 

 

 

 

 

 

(4,924

)

Purchase of noncontrolling interest

 

 

(10,981

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(10,981

)

Other, net

 

 

(284

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(284

)

Advances to affiliates

 

 

(7,312

)

 

 

(148,320

)

 

 

(78,287

)

 

 

 

 

 

233,919

 

 

 

 

Net cash provided by (used in)

    investing activities

 

 

(21,900

)

 

 

(148,320

)

 

 

(272,666

)

 

 

(7,312

)

 

 

233,919

 

 

 

(216,279

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to unitholders

 

 

(180,705

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(180,705

)

Distributions to Series A Preferred unitholders

 

 

(28,500

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(28,500

)

Borrowings under Revolving Credit

    Facility

 

 

 

 

 

289,000

 

 

 

 

 

 

 

 

 

 

 

 

289,000

 

Repayments under Revolving Credit

    Facility

 

 

 

 

 

(84,000

)

 

 

 

 

 

 

 

 

 

 

 

(84,000

)

Debt issuance costs

 

 

 

 

 

(344

)

 

 

 

 

 

 

 

 

 

 

 

(344

)

Other, net

 

 

(2,913

)

 

 

 

 

 

(1,273

)

 

 

 

 

 

 

 

 

(4,186

)

Advances from affiliates

 

 

226,607

 

 

 

 

 

 

 

 

 

7,312

 

 

 

(233,919

)

 

 

 

Net cash (used in) provided by

   financing activities

 

 

14,489

 

 

 

204,656

 

 

 

(1,273

)

 

 

7,312

 

 

 

(233,919

)

 

 

(8,735

)

Net change in cash and cash

    equivalents

 

 

59

 

 

 

155

 

 

 

2,701

 

 

 

 

 

 

 

 

 

2,915

 

Cash and cash equivalents,

    beginning of period

 

 

126

 

 

 

75

 

 

 

1,229

 

 

 

 

 

 

 

 

 

1,430

 

Cash and cash equivalents, end of

    period

 

$

185

 

 

$

230

 

 

$

3,930

 

 

$

 

 

$

 

 

$

4,345

 

 

158


Table of Contents

 

 

 

Year ended December 31, 2017

 

 

 

SMLP

 

 

Co-Issuers

 

 

Guarantor Subsidiaries

 

 

Non-Guarantor Subsidiaries

 

 

Consolidating adjustments

 

 

Total

 

 

 

(In thousands)

 

Cash flows from operating

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash provided by (used in)

    operating activities

 

$

7,122

 

 

$

(68,915

)

 

$

299,625

 

 

$

 

 

$

 

 

$

237,832

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from investing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Capital expenditures

 

 

(3,041

)

 

 

 

 

 

(121,174

)

 

 

 

 

 

 

 

 

(124,215

)

Proceeds from asset sales

 

 

 

 

 

 

 

 

2,300

 

 

 

 

 

 

 

 

 

2,300

 

Contributions to equity method

    investees

 

 

 

 

 

 

 

 

(25,513

)

 

 

 

 

 

 

 

 

(25,513

)

Purchase of noncontrolling interest

 

 

(797

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(797

)

Other, net

 

 

(458

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(458

)

Advances to affiliates

 

 

(278,493

)

 

 

 

 

 

(148,229

)

 

 

 

 

 

426,722

 

 

 

 

Net cash used in investing activities

 

 

(282,789

)

 

 

 

 

 

(292,616

)

 

 

 

 

 

426,722

 

 

 

(148,683

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash flows from financing

    activities:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributions to unitholders

 

 

(179,103

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(179,103

)

Distributions to Series A Preferred unitholders

 

 

(2,375

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(2,375

)

Borrowings under Revolving Credit

    Facility

 

 

 

 

 

247,500

 

 

 

 

 

 

 

 

 

 

 

 

247,500

 

Repayments under Revolving Credit

    Facility

 

 

 

 

 

(634,500

)

 

 

 

 

 

 

 

 

 

 

 

(634,500

)

Debt issuance costs

 

 

 

 

 

(16,390

)

 

 

 

 

 

 

 

 

 

 

 

(16,390

)

Payment of redemption and call

    premiums on senior notes

 

 

 

 

 

(17,932

)

 

 

 

 

 

 

 

 

 

 

 

(17,932

)

Proceeds from ATM Program

    issuances, net of costs

 

 

17,078

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17,078

 

Proceeds from issuance of Series

    A preferred units, net of costs

 

 

293,238

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

293,238

 

Contribution from General Partner

 

 

465

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

465

 

Issuance of senior notes

 

 

 

 

 

500,000

 

 

 

 

 

 

 

 

 

 

 

 

500,000

 

Tender and redemption of senior

    notes

 

 

 

 

 

(300,000

)

 

 

 

 

 

 

 

 

 

 

 

(300,000

)

Other, net

 

 

(2,437

)

 

 

 

 

 

(691

)

 

 

 

 

 

 

 

 

(3,128

)

Advances from affiliates

 

 

148,229

 

 

 

290,261

 

 

 

(11,768

)

 

 

 

 

 

(426,722

)

 

 

 

Net cash provided by (used in) financing

    activities

 

 

275,095

 

 

 

68,939

 

 

 

(12,459

)

 

 

 

 

 

(426,722

)

 

 

(95,147

)

Net change in cash and cash

    equivalents

 

 

(572

)

 

 

24

 

 

 

(5,450

)

 

 

 

 

 

 

 

 

(5,998

)

Cash and cash equivalents,

    beginning of period

 

 

698

 

 

 

51

 

 

 

6,679

 

 

 

 

 

 

 

 

 

7,428

 

Cash and cash equivalents, end of

    period

 

$

126

 

 

$

75

 

 

$

1,229

 

 

$

 

 

$

 

 

$

1,430

 

 

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19. UNAUDITED QUARTERLY FINANCIAL DATA

Summarized information on the consolidated results of operations for each of the quarters during the two-year period ended December 31, 2019, follows.

 

 

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

 

$

(327,083

)

 

$

(10,645

)

 

$

4,809

 

 

$

(36,914

)

Less net income and IDRs

    attributable to General Partner

 

 

 

 

 

 

 

 

 

 

 

12

 

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

 

$

(334,266

)

 

$

(17,770

)

 

$

(2,316

)

 

$

(44,051

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Loss per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common unit - basic

 

$

(3.79

)

 

$

(0.21

)

 

$

(0.03

)

 

$

(0.58

)

Common unit - diluted

 

$

(3.79

)

 

$

(0.21

)

 

$

(0.03

)

 

$

(0.58

)

 

 

 

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 income (loss) attributable to

    SMLP

 

$

38,654

 

 

$

57,430

 

 

$

(49,971

)

 

$

(3,930

)

Less net income and IDRs

    attributable to General Partner

 

 

2,907

 

 

 

3,279

 

 

 

1,140

 

 

 

2,058

 

Less net income attributable to

    Series A Preferred Units

 

 

7,125

 

 

 

7,125

 

 

 

7,125

 

 

 

7,125

 

Net income (loss) attributable to

    common limited partners

 

$

28,622

 

 

$

47,026

 

 

$

(58,236

)

 

$

(13,113

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per limited partner unit:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common unit - basic

 

$

0.39

 

 

$

0.64

 

 

$

(0.79

)

 

$

(0.18

)

Common unit - diluted

 

$

0.39

 

 

$

0.64

 

 

$

(0.79

)

 

$

(0.18

)

 

20. SUBSEQUENT EVENTS

We have evaluated subsequent events for recognition or disclosure in the consolidated financial statements and no events have occurred that require adjustment to or disclosure in the consolidated financial statements.

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

There have been no changes in, or disagreements with, accountants on accounting and financial disclosure matters during the years ended December 31, 2019 and 2018.

Item 9A. Controls and Procedures.

Disclosure Controls and Procedures

We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports that we file or submit to the Securities and Exchange Commission under the Exchange Act, is recorded, processed, summarized and reported within the time periods specified by the Commission’s rules and forms, and that information is accumulated and communicated to the management of our General Partner, including our General Partner’s principal executive and principal financial officers (whom we refer to as the Certifying Officers), as appropriate to allow timely decisions regarding required disclosure. SMLP’s management, with the participation of the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner, has evaluated the effectiveness of SMLP’s disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this annual report (the "Evaluation Date"). Based on such evaluation, the Chief Executive Officer and Chief Financial Officer of SMLP's General Partner have concluded that, as of the Evaluation Date, SMLP’s disclosure controls and procedures are effective.

Changes in Internal Control Over Financial Reporting

There have not been any changes in SMLP’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fourth fiscal quarter of 2019 that have materially affected, or are reasonably likely to materially affect, SMLP's internal control over financial reporting.

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Management’s Annual Report on Internal Control Over Financial Reporting

Our General Partner is responsible for establishing and maintaining adequate internal control over financial reporting for the Partnership. With our participation, an evaluation of the effectiveness of our internal control over financial reporting was conducted as of December 31, 2019, based on the framework and criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management has concluded that our internal control over financial reporting was effective as of December 31, 2019. Our independent registered public accounting firm has issued an audit report on our internal control over financial reporting, included below of this report.

/s/ Heath Deneke

Heath Deneke

President and Chief Executive Officer, Summit Midstream GP, LLC (the General Partner of SMLP)

 

/s/ Marc D. Stratton

Marc D. Stratton

Executive Vice President and Chief Financial Officer, Summit Midstream GP, LLC (the General Partner of

SMLP)

 

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of Summit Midstream, GP, LLC and the unitholders of Summit Midstream Partners, LP Houston, Texas

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Summit Midstream Partners, LP and subsidiaries (the "Partnership") as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Partnership and our report dated March 9, 2020 expressed an unqualified opinion on those financial statements based on our audit and the report of other auditors.

Basis for Opinion

The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

An entity’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. An entity’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the entity are being made only in accordance with authorizations of management and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the entity’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Atlanta, Georgia
March 9, 2020

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Item 9B. Other Information.

None.

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PART III

Item 10. Directors, Executive Officers and Corporate Governance.

Management of Summit Midstream Partners, LP

We are managed by the directors and executive officers of our General Partner, Summit Midstream GP, LLC. Our General Partner is not elected by our unitholders and will not be subject to re-election in the future. Summit Investments, which is controlled by Energy Capital Partners, owns and controls SMP Holdings, the sole owner of our General Partner. SMP Holdings has the right to appoint the entire Board of Directors, including our independent directors. All decisions of the Board of Directors will require the affirmative vote of a majority of all of the directors constituting the board, provided that such majority includes at least a majority of the directors designated as an "Energy Capital Partner Designated Director" by Energy Capital Partners. The Energy Capital Partner Designated Directors are Matthew F. Delaney, Peter Labbat, Thomas K. Lane, Scott A. Rogan and Jeffrey R. Spinner. Our unitholders are not entitled to directly or indirectly participate in our management or operations. Our General Partner is liable, as General Partner, for all of our debts (to the extent not paid from our assets), except for indebtedness (including the outstanding indebtedness under our Revolving Credit Facility) or other obligations that are made specifically nonrecourse to it. Whenever possible, we intend to incur indebtedness that is nonrecourse to our General Partner.

Our General Partner's limited liability company agreement provides that the Board of Directors must obtain the approval of members representing a majority interest in our General Partner for certain actions affecting us. These include actions related to:

 

transactions with affiliates;

 

entering into any hedging transactions that are not in compliance with GAAP;

 

the voluntary liquidation, wind-up or dissolution of us or any of our subsidiaries;

 

making any election that would result in us being classified as other than a partnership or a disregarded entity for U.S. federal income tax purposes;

 

filing or consenting to the filing of any bankruptcy, insolvency or reorganization petition for relief from debtors or protection from creditors naming us or any of our subsidiaries; and

 

effecting a material amendment to our General Partner's limited liability company agreement.

Currently, SMP Holdings is the sole member of our General Partner.

Committees of the Board of Directors

The Board of Directors has an Audit Committee, a Conflicts Committee and a Compensation Committee and may have such other committees as the Board of Directors shall determine from time to time.

The table below shows the current membership of each standing board committee and indicates which directors are independent directors.

 

Name

 

Audit Committee

 

Conflicts Committee

 

Compensation Committee

 

Independent Director

Matthew F. Delaney

 

 

 

 

 

 

 

No

Heath Deneke

 

 

 

 

 

 

 

No

Lee Jacobe

 

Member

 

Member

 

 

 

Yes

Peter Labbat

 

 

 

 

 

 

 

No

Thomas K. Lane

 

 

 

 

 

Chair

 

No

Jerry L. Peters

 

Chair

 

Member

 

 

 

Yes

Scott A. Rogan

 

 

 

 

 

 

 

No

Jeffrey R. Spinner

 

 

 

 

 

Member

 

No

Robert M. Wohleber

 

Member

 

Chair

 

Member

 

Yes

 

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Each of the standing committees of the Board of Directors will have the composition and responsibilities described below.

Audit Committee.  Mr. Jacobe, Mr. Peters and Mr. Wohleber serve as the members of the Audit Committee. Mr. Peters serves as the chair of our Audit Committee. In this role, Mr. Peters satisfies the SEC and New York Stock Exchange rules regarding independence and qualifies as an Audit Committee financial expert.

The Audit Committee assists the Board of Directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and corporate policies and controls. The Audit Committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof, and pre-approve any non-audit services to be rendered by our independent registered public accounting firm. The Audit Committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm has unrestricted access to the Audit Committee.

Our Audit Committee has adopted an audit committee charter, which is publicly available on our website under the "Corporate Governance" subsection of the “Investors” section at www.summitmidstream.com.

Conflicts Committee.  At the direction of our General Partner, our Conflicts Committee will review specific matters that may involve conflicts of interest in accordance with the terms of our Partnership Agreement. The Conflicts Committee will determine the resolution of the conflict of interest that is in the best interests of the Partnership. There is no requirement that our General Partner seek the approval of the Conflicts Committee for the resolution of any conflict. The members of the Conflicts Committee may not be officers or employees of our General Partner or directors, officers, or employees of any of its affiliates. They may not hold any ownership interest in our General Partner or us and our subsidiaries other than common units and other awards that are granted under our incentive plans in place from time to time. Furthermore, the members of the Conflicts Committee must meet the independence and experience standards established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. Mr. Jacobe, Mr. Peters and Mr. Wohleber currently serve as the members of our Conflicts Committee, with Mr. Wohleber serving as chair of the committee.

Any matters approved by the Conflicts Committee in good faith will be conclusively deemed to be approved by all of our partners and not a breach by our General Partner of any duties it may owe us or our unitholders. Any unitholder challenging any matter approved by the Conflicts Committee will have the burden of proving that the members of the Conflicts Committee did not subjectively believe that the matter was in the best interests of the Partnership. Moreover, any acts taken or omitted to be taken in reliance upon the advice or opinions of experts such as legal counsel, accountants, appraisers, management consultants and investment bankers, where our General Partner (or any members of the Board of Directors including any member of the Conflicts Committee) reasonably believes the advice or opinion to be within such person's professional or expert competence, shall be conclusively presumed to have been taken or omitted in good faith.

Compensation Committee.  Mr. Lane, Mr. Spinner and Mr. Wohleber serve as the members of the Compensation Committee, with Mr. Lane serving as chair of the committee. The Compensation Committee provides oversight, administers and makes decisions regarding our executive compensation policies and incentive plans. Although our common units are listed on the NYSE, we qualify for the “Limited Partnership” exemption to the NYSE rule that would otherwise require listed companies to have an independent compensation committee with a written charter.

Directors and Executive Officers

Directors of our General Partner are appointed for a term of one year and hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Officers serve at the discretion of the Board of Directors.

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The following table shows information for the directors and executive officers of our General Partner as of February 27, 2020.

 

Name

 

Age

 

 

Position with Summit Midstream GP, LLC

Heath Deneke

 

 

46

 

 

President and Chief Executive Officer, Director

Leonard W. Mallett

 

 

63

 

 

Executive Vice President and Chief Operations Officer

Marc D. Stratton

 

 

42

 

 

Executive Vice President and Chief Financial Officer

Brock M. Degeyter

 

 

43

 

 

Executive Vice President, General Counsel and Chief

Compliance Officer

Louise E. Matthews

 

 

50

 

 

Executive Vice President and Chief Administration Officer

Matthew F. Delaney

 

 

33

 

 

Director

Lee Jacobe

 

 

52

 

 

Director

Peter Labbat

 

 

54

 

 

Director

Thomas K. Lane

 

 

63

 

 

Director

Jerry L. Peters

 

 

62

 

 

Director

Scott A. Rogan

 

 

49

 

 

Director

Jeffrey R. Spinner

 

 

38

 

 

Director

Robert M. Wohleber

 

 

69

 

 

Director

 

Heath Deneke has been President and Chief Executive Officer and a director of our General Partner since his appointment effective September 16, 2019. Prior to joining our General Partner, Mr. Deneke served as Executive Vice President, Chief Operating Officer for Crestwood Equity Partners LP and Crestwood Midstream Partners LP from August 2017 through April 2019. Previously, Mr. Deneke was the President, Chief Operating Officer of Crestwood’s Pipeline Services Group from June 2015 to August 2017, where he was responsible for the commercial development and operations of Crestwood’s midstream businesses, including assets in the Marcellus, Bakken, PRB Niobrara, Delaware, Permian, Barnett, Granite Wash, Fayetteville and Haynesville shale plays. Prior to that, he served as President of Crestwood’s Natural Gas Business Unit from October 2013 to June 2015 and as Senior Vice President and Chief Commercial Officer of Crestwood’s legacy business from August 2012 until October 2013. Prior to joining Crestwood, Mr. Deneke served in various management positions at El Paso Corporation and its affiliates, including Vice President of Project Development and Engineering for the Pipeline Group, Director of Marketing and Asset Optimization for Tennessee Gas Pipeline Company, LLC and Manager of Business Development and Strategy for Southern Natural Gas Company, LLC. Mr. Deneke holds a bachelor’s degree in Mechanical Engineering from Auburn University.

Leonard W. Mallett has been Executive Vice President and Chief Operating Officer of our General Partner since December 2015, and also served as President and Chief Executive Officer and director of our General Partner on an interim basis from February 21, 2019 until Mr. Deneke’s appointment effective September 16, 2019. Prior to joining our General Partner, Mr. Mallett served as Senior Vice President of Engineering for Enterprise, where he was responsible for the engineering, project management, sourcing and technical support functions supporting all of Enterprise’s pipeline and related plants. Mr. Mallett began his career with TEPPCO as a Project Engineer and spent the next three decades working with TEPPCO and successor entities in various engineering, transportation, and operations roles. At the end of 2006, Enterprise bought TEPPCO’s General Partner from Duke Energy Field Services, at which time Mr. Mallett was serving as SVP of Operations for TEPPCO. Post-merger, Mr. Mallett was named SVP-Environmental, Health and Safety. Mr. Mallett holds a Bachelor of Science in Mechanical Engineering from Prairie View A&M University and a Master of Business Administration from Houston Baptist University.

Marc D. Stratton has been the Executive Vice President and Chief Financial Officer of our General Partner since December 2018. Mr. Stratton joined Summit Investments as a founding member in 2009 and has held various senior management roles at the Company including, Senior Vice President of Finance, Treasurer and Head of Investor Relations. Prior to joining the Company, Mr. Stratton served as a midstream infrastructure investment analyst at ING Investment Management and, prior to that, as Vice President of Project Finance at SunTrust Robinson Humphrey. Mr. Stratton has over 17 years of oil and gas industry experience in corporate finance and holds a bachelor’s degree in Economics from Denison University.

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Brock M. Degeyter has been the Executive Vice President, General Counsel and Chief Compliance Officer of our General Partner since March 2015. Previously, he served as Senior Vice President and General Counsel from January 2012 until March 2015. Mr. Degeyter has been the Chief Compliance Officer of our General Partner since January 2014. Mr. Degeyter also served as Secretary of our General Partner from May 2012 until February 21, 2019. Prior to joining Summit Investments, Mr. Degeyter worked in the corporate legal department for Energy Future Holdings (formerly TXU Corp.) from January 2007 through December 2011 where he served as Director of Corporate Governance and Senior Counsel. Prior to joining Energy Future Holdings, Mr. Degeyter was engaged in private practice with the firm of Correro Fishman Haygood Phelps Walmsley & Casteix LLP from May 2002 through December 2006. Mr. Degeyter is licensed to practice law in the states of Texas and Louisiana. Mr. Degeyter received a B.A. in Political Science from Louisiana State University and a J.D. from Loyola University College of Law in New Orleans.

Louise E. Matthews has been Executive Vice President and Chief Administration Officer since February 21, 2019. Previously, she served as Senior Vice President, Human Resources and Corporate Communications from March 2016 to February 2019, and Vice President, Human Resources from May 2013 to March 2016. Prior to joining our General Partner, Ms. Matthews served as Senior Vice President at SunTrust Bank (“SunTrust”) from November 2010 to May 2013, leading the Human Resources organization supporting Enterprise Technology and Operations for all segments, including Wholesale, Investment Banking, Retail and Corporate Functions. While with SunTrust, Ms. Matthews also served as a certified executive coach. Prior to her time at SunTrust, Ms. Matthews served as Vice President of Human Resources with ING Investment Management. Ms. Matthews has also served as HR Director for Sprint, Integrated Health Services and Jekyll Island Authority. Ms. Matthews earned her Master of Business Administration and Bachelor of Business Administration from Georgia Southern University. Ms. Matthews intends to resign from her position as an executive officer of the General Partner and terminate her employment with the Company effective April 30, 2020.

Matthew F. Delaney has served as a director of our General Partner since May 2016 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Mr. Delaney has been an investment professional at Energy Capital Partners since 2011. Prior to joining Energy Capital Partners, Mr. Delaney worked in the Investment Banking Division at Morgan Stanley focusing on energy mergers and acquisitions. Mr. Delaney received a B.A. in Economics from Amherst College. Mr. Delaney was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry, and his financial and business expertise.

Lee Jacobe has served as a director of our General Partner since April 2019. Mr. Jacobe currently serves as an advisor with respect to energy investments for Kelso & Company, a New York based private equity firm. From 2008 through 2018, Mr. Jacobe was involved in various capacities at Barclays Investment Banking – Energy Group, including head of the firm’s midstream coverage effort, co-head of its US Oil & Gas group, and Vice Chairman of the firm. From 1993 through 2008, Mr. Jacobe was an investment banker in the energy group at Lehman Brothers, including serving as a managing director from 2001–2008. Mr. Jacobe began his investment banking career at Wasserstein Perella & Co. in 1990. He has a B.B.A., with a major in Finance, from the University of Texas at Austin. Mr. Jacobe has valuable and extensive experience in the energy banking sector, including a vast array of experience in corporate finance, capital structure, and the evaluation of financial risks associated with publicly traded partnerships that invest in midstream infrastructure.

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Peter Labbat has served as a director of our General Partner since August 2016 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Mr. Labbat is Managing Partner of Energy Capital Partners and has been an investment professional at Energy Capital Partners since 2006. Prior to joining Energy Capital Partners, Mr. Labbat spent 13 years in Goldman Sachs’ Investment Banking Division. He currently serves on the boards of Triton Power Holdings Limited, Sendero Midstream Partners, LP, Next Wave Energy Partners, LP and NCSG Crane & Heavy Haul Corp. Mr. Labbat received a B.A. in Economics from Georgetown University and an M.B.A. from the Wharton School at the University of Pennsylvania. Mr. Labbat was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

Thomas K. Lane has served as director of our General Partner since May 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners, which controls Summit Investments, the sole owner of SMP Holdings, the entity that owns and controls our General Partner. Additionally, Mr. Lane serves as the chair of the Compensation Committee. Mr. Lane has served on the board of WEC Energy Group since January 2020 and is Vice Chairman of Energy Capital Partners. He was previously a partner of Energy Capital Partners from 2005 to 2016. Prior to joining Energy Capital Partners, Mr. Lane worked for 17 years in the Investment Banking Division at Goldman Sachs. As a Managing Director at Goldman Sachs, Mr. Lane had senior-level coverage responsibility for electric and gas utilities, independent power companies and merchant energy companies throughout the United States. Mr. Lane received a B.A. in economics from Wheaton College and an MBA from the University of Chicago. Mr. Lane was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

Jerry L. Peters has served as a director of our General Partner since September 2012. Additionally, Mr. Peters served as the chair of the Conflicts Committee of our General Partner until November 2012 and serves as the chair and financial expert of the Audit Committee of our General Partner. Mr. Peters served as the Chief Financial Officer of Green Plains Inc., a publicly traded vertically-integrated ethanol producer, from June 2007 until his retirement in September 2017. In 2015, Mr. Peters was appointed Chief Financial Officer and Director of the General Partner of Green Plains Partners LP, a publicly traded partnership engaged in fuel storage and transportation services. He retired from his role as Chief Financial Officer of the General Partner of Green Plains Partners LP in September 2017, but remains on the Board of Directors. Prior to joining Green Plains, Mr. Peters served as Senior Vice President—Chief Accounting Officer for ONEOK Partners, L.P. from May 2006 to April 2007, as Chief Financial Officer of ONEOK Partners, L.P. from July 1994 to May 2006, and in various senior management roles of ONEOK Partners, L.P. from 1985 to May 2006. Prior to joining ONEOK Partners, Mr. Peters was employed by KPMG LLP as a certified public accountant from 1980 to 1985. In October 2017, Mr. Peters joined the board of the general partner of USA Compression Partners LP and served as chair and financial expert of the audit committee thereof. Mr. Peters resigned from the board of the general partner of USA Compression Partners LP in March 2018. Mr. Peters received an MBA from Creighton University with an emphasis in finance and a B.S. in Business Administration from the University of Nebraska—Lincoln. Mr. Peters' extensive executive, financial and operational experience bring important and necessary skills to the Board of Directors.

Scott A. Rogan has served as a director of our General Partner since February 2014 and was appointed to the board in connection with his affiliation with Energy Capital Partners. Mr. Rogan joined Energy Capital Partners as a principal in February 2014. For five years prior to joining Energy Capital Partners, Mr. Rogan was employed by Barclays Capital ("Barclays") as a Managing Director working in the investment banking division of the natural resources group. Prior to its merger with Barclays in 2008, Mr. Rogan worked for over 10 years in investment banking for Lehman Brothers. Mr. Rogan received a bachelor’s degree in business administration and a master’s degree in professional accounting from the University of Texas at Austin as well as a master’s degree in business administration from the University of Chicago. Mr. Rogan was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

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Jeffrey R. Spinner has served as a director of our General Partner since November 2012 and was appointed to the board in connection with his affiliation with Energy Capital Partners. Mr. Spinner has been an investment professional at Energy Capital Partners since 2006. Prior to joining Energy Capital Partners, Mr. Spinner worked in the Natural Resources Investment Banking Group at Banc of America Securities. Mr. Spinner received a B.S. in Economics from Duke University. Mr. Spinner was selected to serve as a director on the board due to his affiliation with Energy Capital Partners, his knowledge of the energy industry and his financial and business expertise.

Robert M. Wohleber has served as a director of our General Partner since August 2013. Mr. Wohleber served as Senior Vice President and Chief Financial Officer of Kerr-McGee Corporation, an oil and gas exploration and production company, from December 1999 to August 2006. From 1996 to 1998, he served as Senior Vice President and Chief Financial Officer of Freeport-McMoran, Inc., one of the largest phosphate fertilizer producers in the United States. He holds a B.B.A. from the University of Notre Dame and an M.B.A. from the University of Pittsburgh. Mr. Wohleber's extensive executive and financial experience in the oil and gas industry bring important and necessary skills to the Board of Directors.

Code of Business Conduct and Ethics

The Board of Directors has adopted a Code of Business Conduct and Ethics which sets forth SMLP’s policy with respect to business ethics and conflicts of interest. The Code of Business Conduct and Ethics is intended to ensure that the employees, officers and directors of SMLP and its General Partner conduct business with the highest standards of integrity and in compliance with all applicable laws and regulations. It applies to the employees, officers and directors of SMLP and its General Partner, including the principal executive officer, principal financial officer and principal accounting officer or controller, or persons performing similar functions (the "Senior Financial Officers"). The Code of Business Conduct and Ethics also incorporates expectations of the Senior Financial Officers that enable us to provide accurate and timely disclosure in our filings with the SEC and other public communications. The Code of Business Conduct and Ethics is publicly available on our website under the "Corporate Governance" subsection of the “Investors” section at www.summitmidstream.com and is also available free of charge on written request to the Secretary at the Woodlands office address given under the "Contact" section on our website.

Corporate Governance Guidelines

Our Corporate Governance Guidelines, which are available on our website under the “Corporate Governance” subsection of the “Investors” section at www.summitmidstream.com, provide guidelines for the governance of the Company. The Corporate Governance Guidelines specifically provide, among other things, that (i) Jerry L. Peters, as the chairman of our Audit Committee, shall preside over any executive sessions, and (ii) interested parties may communicate directly with our independent directors by submitting a specially marked envelope to the Secretary of our General Partner.

Delinquent Section 16(a) Reports

Section 16(a) of the Exchange Act requires SMLP's directors and executive officers, and persons who own more than 10% of a registered class of our securities, to file with the SEC initial reports of ownership and reports of changes in ownership of SMLP's common units and other equity securities. Based on our records, we believe that all directors, executive officers and persons who own more than 10% of our common units have complied with the reporting requirements of Section 16(a) except for the following. On February 7, 2020, Energy Capital Partners II, LLC and Summit Midstream Partners, LLC filed delinquent Section 16(a) reports relating to the second amendment to that certain Contribution Agreement between SMP Holdings and the Partnership dated February 25, 2016, as amended, pursuant to which the Partnership issued 10,714,285 common units to SMP Holdings on November 15, 2019.

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Item 11. Executive Compensation.

This Compensation Discussion and Analysis (“CD&A”) provides information regarding the compensation of certain of our executive officers as reported in the Summary Compensation Table and other tables in this document. In this CD&A, we review the compensation decisions and rationale for those decisions relating to the three persons who served as our principal executive officer during the past fiscal year, the person who served as our principal financial officer during the past fiscal year, and our next three most highly compensated executive officers.

The following describes the material components of our executive compensation program for the following individuals, who are referred to as the "Named Executive Officers" or “NEOs”:

Heath Deneke, President and Chief Executive Officer (1)

Steven J. Newby, former President and Chief Executive Officer (2)

Leonard W. Mallett, Executive Vice President and Chief Operations Officer (3)

Marc D. Stratton, Executive Vice President and Chief Financial Officer

Brock M. Degeyter, Executive Vice President, General Counsel and Chief Compliance Officer

Brad N. Graves, Executive Vice President and Chief Commercial Officer (4)

 

Louise E. Matthews, Executive Vice President and Chief Administration Officer

(1) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019.

(2) Mr. Newby served as our President and Chief Executive Officer until his resignation effective February 21, 2019. Mr. Newby’s employment terminated effective February 28, 2019.

(3) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019.

(4) Mr. Graves’ employment terminated effective December 31, 2019.

The NEOs are employees of Summit Investments and executive officers of our General Partner. Certain of the NEOs split their working time between SMLP's business and their responsibilities for Summit Investments and its affiliates other than us. Under the terms of our Partnership Agreement, our General Partner determines the portion of the NEOs' compensation that is allocated to us. The percentage of total compensation allocated to us in 2019 for each NEO is as follows: 100% for Mr. Deneke; 55% for Mr. Newby; 87.5% for Mr. Mallett; 75% for Mr. Stratton; 70% for Mr. Degeyter; 80% for Mr. Graves; and 95% for Ms. Matthews.

The Compensation Committee provides oversight, administers and makes decisions regarding our compensation policies and plans.

Compensation Philosophy and Objectives

We seek to provide reasonable and competitive rewards to executives through compensation and benefit programs structured to:

Attract and retain outstanding talent

Drive achievement of short-term and long-term goals

Reward successful execution of objectives

Reinforce company culture and leadership competencies

Align executives with the interests of our unitholders

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We employ a pay-for-performance philosophy when designing executive compensation opportunities. Thus, a portion of an executive’s target compensation is performance based through linkage to the achievement of financial and other measures deemed to be drivers in the creation of unitholder value. While the Compensation Committee does not set a specific target allocation among the elements of total direct compensation, a portion of the compensation opportunity available to each of our NEOs is, by design, tied to the Partnership’s annual and long-term performance.

Compensation of Named Executive Officers

The Compensation Committee establishes the target total direct compensation of our executives and administers other benefit programs. The Compensation Committee engages an independent compensation consultant (the “Compensation Consultant”) who provides the Compensation Committee with data, analysis and advice on the structure and level of executive compensation. The Compensation Consultant participates in Compensation Committee meetings and executive sessions of the Compensation Committee meetings as requested. The Compensation Consultant may work with our management on various matters for which the Compensation Committee is responsible. However, the Compensation Committee, not management, directs the activities of the Compensation Consultant. We consider the Compensation Consultant to be independent of the Partnership according to current NYSE listing requirements and SEC guidance. BDO USA L.L.P. served as Compensation Consultant until September 2019 when it was replaced by Willis Towers Watson.

Partnership management, in consultation with the Compensation Committee chair and the Compensation Consultant, prepares materials for the Compensation Committee relevant to matters under consideration by the Compensation Committee, including market data provided by the Compensation Consultant and recommendations of our Chief Executive Officer (the "CEO") regarding compensation of the other executives. The Compensation Committee works directly with the Compensation Consultant on our CEO’s compensation as required.

Based on market data which we use as a reference, we believe compensation of our NEOs is reasonably competitive with opportunities available to officers holding similar positions at comparable midstream companies. We seek to set compensation levels for each component of total direct compensation based on our assessment of market practices at or near the median. The Compensation Committee adjusts target compensation for each NEO above or below the median, taking into consideration experience, performance, internal equity and other relevant circumstances.

During the Compensation Committee’s annual review of executive compensation, the Compensation Consultant provided the Compensation Committee with an analysis of positions comparable to the NEOs at peer companies. To develop these exhibits, information from peer company public filings was compiled, including public company proxy statements and annual reports on Form 10-K. The peer group used for 2019 executive compensation consisted of publicly traded midstream companies with whom we compete for executive talent.

The peer group comprised the following companies:

 

Crestwood Equity Partners, LP

 

NuStar Energy, LP

DCP Midstream, LP

 

Phillips 66 Partners LP

Enable Midstream Partners, LP

 

SemGroup Corporation

EQM Midstream Partners, LP

 

Tallgrass Energy, LP

Genesis Energy, LP

 

Targa Resources Corp.

Hess Midstream Partners, LP

 

 

Noble Midstream Partners, LP

 

 

 

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The compensation analysis encompassed the primary components of total direct compensation, including annual base salary, annual short-term incentive and long-term incentive awards for the NEOs of these peer group companies. The Compensation Committee considered the information provided to ascertain whether the compensation of our NEOs is aligned with our compensation philosophy and competitive with the compensation for executive officers of the peer group companies. The Compensation Committee reviewed the compensation analysis to confirm that our compensation programs were supporting a competitive total compensation approach that emphasizes incentive-based compensation and appropriately rewards achievement of our objectives. For 2019, the target total direct compensation for the NEOs as set by the Compensation Committee is summarized below. Each element is further discussed in this CD&A.

Components of Executive Compensation

 

Name and Principal Position (1)

 

Base Salary ($)

 

 

2019 Target Annual Bonus: Percent of Base Salary (%)

 

 

2019 Target LTIP Award: Percent of Base Salary (%)

 

 

2019 LTIP Target Award Value ($)

 

 

2019 Target Total Direct Compensation ($)

 

Heath Deneke (2) (3)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

President and Chief Executive Officer

 

 

600,000

 

 

 

150

 

 

 

275

 

 

 

1,650,000

 

 

 

3,150,000

 

Marc D. Stratton

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Financial Officer

 

 

350,000

 

 

 

100

 

 

 

150

 

 

 

525,000

 

 

 

1,225,000

 

Brock M. Degeyter

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

380,000

 

 

 

100

 

 

 

150

 

 

 

570,000

 

 

 

1,330,000

 

Brad N. Graves (4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Commercial Officer

 

 

400,000

 

 

 

100

 

 

 

150

 

 

 

600,000

 

 

 

1,400,000

 

Leonard W. Mallett (5)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Operations Officer

 

 

400,000

 

 

 

100

 

 

 

150

 

 

 

600,000

 

 

 

1,400,000

 

Louise E. Matthews

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Administration Officer

 

 

300,000

 

 

 

100

 

 

 

150

 

 

 

450,000

 

 

 

1,050,000

 

 

(1) Mr. Newby is omitted from this table because he resigned from his position as President and Chief Executive Officer effective February 21, 2019, before the Compensation Committee’s annual review and setting of the NEOs’ target total direct compensation.

(2) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. Because Mr. Deneke was hired after the Compensation Committee’s annual review of executive compensation, the Compensation Committee played no role in the determination of Mr. Deneke’s target total direct compensation in 2019. Instead, Mr. Deneke’s target total direct compensation was determined by the General Partner and is reflected in his employment agreement.

(3) Although Mr. Deneke’s target annual bonus set forth in his employment agreement is 150% of his base salary, his employment agreement further provides that his 2019 bonus shall be prorated for the period of time he actually served as President and Chief Executive Officer in 2019.

(4) Mr. Graves’ employment terminated effective December 31, 2019.

(5) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019.

The primary elements of compensation for the NEOs are base salary, annual incentive compensation and long-term equity-based compensation awards. The NEOs also receive certain retirement, health, welfare and additional benefits.

Base Salary.  The base salaries for our NEOs are reviewed annually by the Compensation Committee. Base salaries for our NEOs have generally been set at levels deemed necessary to attract and retain individuals with superior talent.

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The base salaries of our NEOs, a portion of which are allocated to and reimbursed by Summit Investments and its affiliates other than us, are set forth in the following table:

 

Name and Principal Position

 

2019 Base Salary ($)

 

Heath Deneke (1)

 

 

 

 

President and Chief Executive Officer

 

 

600,000

 

Steven J. Newby (2)

 

 

 

 

President and Chief Executive Officer (former)

 

 

612,000

 

Marc D. Stratton

 

 

 

 

Executive Vice President and Chief Financial Officer

 

 

350,000

 

Brock M. Degeyter

 

 

 

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

380,000

 

Brad N. Graves (3)

 

 

 

 

Executive Vice President and Chief Commercial Officer

 

 

400,000

 

Leonard W. Mallett (4)

 

 

 

 

Executive Vice President and Chief Operations Officer

 

 

400,000

 

Louise E. Matthews

 

 

 

 

Executive Vice President and Chief Administration Officer

 

 

300,000

 

 

(1) Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019.

(2) Mr. Newby served as our President and Chief Executive Officer until his resignation effective February 21, 2019.

(3) Mr. Graves’ employment terminated effective December 31, 2019.

(4) Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019.

Annual Incentive Compensation.  We provide an annual incentive bonus (“annual bonus”) to drive the achievement of key business results and to recognize NEOs based on their contributions to those results. The annual bonus plan is a cash-based incentive plan. Incentive amounts are intended to provide total cash compensation near the market range for executive officers in comparable positions when target performance is achieved. Annual bonus compensation levels are set above or below the market range to reflect actual performance results as appropriate when performance is greater or less than expectations. Annual bonus payouts may range from 0% to 200% of the target opportunity and may be adjusted at the discretion of the Compensation Committee.

In March 2019, the Compensation Committee established the 2019 annual bonus plan target opportunities as a percentage of base salary for our NEOs other than Mr. Deneke and Mr. Newby. The 2019 targets for Messrs. Stratton, Degeyter, Graves and Mallett and for Ms. Matthews were 100% of their base salaries. The Compensation Committee played no role in the determination of the 2019 annual bonus plan target opportunities for Mr. Deneke, who did not become an employee until September 16, 2019, or for Mr. Newby, who resigned as President and Chief Executive Officer prior to the Compensation Committee’s annual review and setting of the NEOs’ annual bonus plan target opportunities.

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Name and Principal Position (1)

 

2019 Target Annual Bonus:  Percent of Base Salary (%)

 

 

2019 Target Bonus: Dollar Value ($)

 

Heath Deneke (2) (3)

 

 

 

 

 

 

 

 

President and Chief Executive Officer

 

 

150

 

 

 

900,000

 

Marc D. Stratton

 

 

 

 

 

 

 

 

Executive Vice President and Chief Financial Officer

 

 

100

 

 

 

350,000

 

Brock M. Degeyter

 

 

 

 

 

 

 

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

100

 

 

 

380,000

 

Brad N. Graves (4)

 

 

 

 

 

 

 

 

Executive Vice President and Chief Commercial Officer

 

 

100

 

 

 

400,000

 

Leonard W. Mallett (5)

 

 

 

 

 

 

 

 

Executive Vice President and Chief Operations Officer

 

 

100

 

 

 

400,000

 

Louise E. Matthews

 

 

 

 

 

 

 

 

Executive Vice President and Chief Administration Officer

 

 

100

 

 

 

300,000

 

 

(1)

Mr. Newby is omitted from this table because he resigned from his position as President and Chief Executive Officer effective February 21, 2019, before the Compensation Committee’s annual review and setting of the NEOs’ target total direct compensation.

(2)

Mr. Deneke was appointed President and Chief Executive Officer effective September 16, 2019. Because Mr. Deneke was hired after the Compensation Committee’s annual review of executive compensation, the Compensation Committee had no role in the determination of Mr. Deneke’s target annual bonus in 2019. Instead, Mr. Deneke’s target annual bonus in 2019 was set by the terms of his employment agreement.

(3)

Mr. Deneke’s employment agreement provides that his 2019 bonus shall be prorated for the period of time he actually served as President and Chief Executive Officer in 2019.

(4)

Mr. Graves’ employment terminated effective December 31, 2019.

(5)

Mr. Mallett served as our President and Chief Executive Officer on an interim basis from February 21, 2019, the date of Mr. Newby’s resignation, until the appointment of Mr. Deneke effective September 16, 2019.

In 2020, quantitative factors, as reflected in the corporate scorecard applicable to the senior leadership team (the "SLT Scorecard") set the baseline for the annual bonuses for Messrs. Deneke, Stratton, Degeyter and Mallett and for Ms. Matthews, which were subject to further adjustments as explained below. The SLT Scorecard contained four factors, which are considered by the Board of Directors and management as key indicators of the successful execution of our business plan. Those factors were (i) adjusted EBITDA, (ii) distributable cash flow per unit, (iii) controllable expense metric and (iv) health, safety, environmental and regulatory goals.

The annual bonuses paid to Messrs. Newby and Graves were approved by the Board and determined in accordance with their employment agreements, as further described below.

In February 2020, the Compensation Committee and the Board of Directors reviewed the SLT Scorecards for 2019 and determined the level of achievement of each key factor. We exceeded two of our targets: our controllable expense metric and our health, safety, environmental and regulatory goals. We did not meet our adjusted EBITDA target or our distributable cash flow per unit target. These results yielded a calculated SLT Scorecard result of 54% of target.  

In addition to corporate results, additional considerations are applied at the discretion of the CEO, the Compensation Committee and the Board of Directors that may affect the actual annual bonus earned. Those considerations include judgments regarding overall company performance and business events, performance of each NEO’s respective business unit, industry climate and performance, the market for executive talent, demonstrated leadership capabilities and progress on strategic initiatives. Each NEO’s bonus amount, as reflected below, is adjusted up or down in recognition of these additional considerations.

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The Board approved an annual bonus for Mr. Deneke equal to the target bonus set forth in his employment agreement, prorated for the period of time he served as CEO in 2019, or $300,000. Mr. Deneke’s annual bonus payout reflects his demonstrated leadership capabilities for the period of time he was employed by us in 2019, and the fact that he did not serve as Chief Executive Officer for the full year.

Mr. Stratton’s annual bonus payout reflects consideration for the combined performance of the finance and accounting business units. Mr. Stratton was awarded 65% of his target annual bonus in 2019, or $227,500.

Mr. Degeyter’s annual bonus payout reflects consideration for the performance of the legal business unit. Mr. Degeyter was awarded 65% of his target annual bonus in 2019, or $247,000.

Mr. Mallett's annual bonus payout reflects consideration for the combined performance of the engineering, operations and health, safety, environmental and regulatory business units. Mr. Mallett was awarded 65% of his target annual bonus in 2019, or $260,000.

Ms. Matthews’ annual bonus payout reflects consideration for the performance of the administration business unit, including human resources and information technology. Ms. Matthews was awarded 65% of her target annual bonus in 2019, or $195,000.

In connection with their terminations, Messrs. Newby and Graves received prorated annual bonuses for 2019 pursuant to the terms of their employment agreements. Mr. Newby received a prorated annual bonus of $148,389 and Mr. Graves received a prorated annual bonus equal to $400,000.

Only a portion of the annual bonus amounts are allocated to and reimbursed by the Partnership. For a discussion of the cost allocation methodology, please refer to "Reimbursement of Expenses from General Partner" in Item 13. Certain Relationships and Related Transactions, and Director Independence. Based on the foregoing discussion, the annual bonus awards to be paid in March 2020 to our NEOs for 2019 performance are as follows:

 

Name and Principal Position

 

2019 Annual Bonus Payout ($)

 

Heath Deneke

 

 

 

 

President and Chief Executive Officer

 

 

300,000

 

Steven J. Newby (1)

 

 

 

 

Former President and Chief Executive Officer

 

 

148,389

 

Marc D. Stratton

 

 

 

 

Executive Vice President and Chief Financial Officer

 

 

227,500

 

Brock M. Degeyter

 

 

 

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

247,000

 

Brad N. Graves (1)

 

 

 

 

Executive Vice President and Chief Commercial Officer

 

 

400,000

 

Leonard W. Mallett (2)

 

 

 

 

Executive Vice President and Chief Operations Officer

 

 

260,000

 

Louise E. Matthews

 

 

 

 

Executive Vice President and Chief Administration Officer

 

 

195,000

 

 

(1)

The amounts reflected are prorated annual bonuses paid to Messrs. Newby and Graves upon their terminations in accordance with their employment agreements. Mr. Newby resigned from his position as President and Chief Executive Officer effective February 21, 2019 and his employment terminated on February 28, 2019. Mr. Graves’ employment terminated on December 31, 2019.

(2)

In addition to his annual bonus reflected in the table above, in March 2019 Mr. Mallett received a one-time bonus of $100,000 for his service as President and Chief Executive Officer on an interim basis between the resignation of Mr. Newby and the appointment of Mr. Deneke.

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Long-Term Equity-Based Compensation Awards.  Our General Partner approved the SMLP LTIP pursuant to which eligible officers (including the NEOs), employees, consultants and directors of our General Partner and its affiliates are eligible to receive awards with respect to our equity interests, thereby linking the recipients' compensation directly to the value of SMLP's common units and enhancing our ability to attract and retain superior talent. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors or Compensation Committee, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards.

The SMLP LTIP is designed to promote our interests, as well as the interests of our unitholders, by aligning the interests of our eligible employees (including the NEOs) and directors with those of common unitholders, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as directors and employees.

SMLP LTIP award guidelines for NEOs are designed to attract, retain and motivate the NEOs and were determined using the Compensation Consultant's analysis for individuals in comparable positions and an analysis of the scope of their roles and duties. These guidelines set an annual equity award target in the amount of 150% of base salary for Messrs. Stratton, Degeyter, Graves and Mallett, and for Ms. Matthews. Pursuant to his employment agreement, Mr. Deneke’s target equity award for 2019 was 275% of his base salary. Mr. Newby was not granted an LTIP award in 2019.

Although LTIP is usually granted once per fiscal year, on or about March 15th, in 2019 there were three separate equity grants, described below:

March 2019 Equity Grants. Effective March 15, 2019, based on the recommendation of the Compensation Committee, the Board of Directors approved a grant of phantom units to Messrs. Stratton, Degeyter, Graves and Mallet and to Ms. Matthews. The underlying phantom units vest ratably over a three-year period. Holders of phantom units are entitled to distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. The Compensation Committee selected equity awards that vest contingent on continued service to foster increased unit ownership by the NEOs and as a retention incentive for continued employment with the Partnership.

September 16, 2019 Equity Grant to Mr. Deneke. As an inducement to accept the position of President and Chief Executive Officer of the Company, on September 16, 2019 Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, pursuant to a standalone phantom unit award agreement (the "Award Agreement"). Subject to the terms and conditions of the Award Agreement, the underlying phantom units will vest ratably over a three-year period, and are entitled to distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.

November 15, 2019 “Off-Cycle” Equity Grants to Certain NEOs. On November 15, 2019, as a retention incentive for continued employment with the Partnership, Messrs. Degeyter, Stratton, and Mallett, and Ms. Matthews received an additional grant of 50,000 phantom units with a fair market value of $193,500. The phantom units will “cliff vest” on November 15, 2022, subject to continued employment and accelerated vesting as provided in the applicable award agreement.

All SMLP LTIP grants to our NEOs are subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of the NEO's employment other than for cause, (ii) a termination of the NEO's employment by the officer for good reason (as defined in the NEO's employment agreement), (iii) a termination of the NEO's employment by reason of the NEO's death or disability or (iv) a Change in Control (as defined in the applicable award agreement).

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To calculate the number of phantom units granted to each eligible NEO in March 2019, the Compensation Committee determined the dollar amount of the long-term incentive compensation award, and then granted the number of phantom units that had a fair market value equal to that amount as of market close on the date of the grant. The same calculation was performed with respect to the September 16, 2019 grant to Mr. Deneke except the dollar amount was determined by Partnership management. With respect to the November 15, 2019 grant to certain NEOs, Partnership management determined the number of phantom units to be granted. Phantom unit awards granted in 2019 were as follows:

 

Name and Principal Position

 

2019 Target LTIP Award:  Percent of Base Salary (%)

 

 

2019 Phantom Units Awarded (#) (2)

 

 

2019 SMLP LTIP Award Value ($)

 

Heath Deneke (1)

 

 

 

 

 

 

 

 

 

 

 

 

President and Chief Executive Officer

 

 

275

 

 

 

772,200

 

 

 

4,000,000

 

Marc D. Stratton

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Financial Officer

 

 

150

 

 

 

108,793

 

 

 

768,500

 

Brock M. Degeyter

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

150

 

 

 

113,905

 

 

 

818,500

 

Brad N. Graves

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Commercial Officer

 

 

150

 

 

 

61,349

 

 

 

600,000

 

Leonard W. Mallett

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Operations Officer

 

 

150

 

 

 

116,462

 

 

 

843,500

 

Louise E. Matthews

 

 

 

 

 

 

 

 

 

 

 

 

Executive Vice President and Chief Administration Officer

 

 

150

 

 

 

101,124

 

 

 

693,500

 

___________

(1) Although Mr. Deneke’s employment agreement provides for a target LTIP award valued at 275% of his base salary, in 2019 the value of his initial one-time grant of phantom units was determined by the General Partner.

(2) Amount includes units granted on March 15, 2019 and, as discussed above in this section, September 16, 2019 and November 15, 2019 with respect to certain NEOs.

Retirement, Health and Welfare and Additional Benefits.  The NEOs are eligible to participate in such employee benefit plans and programs as we offer to our employees, subject to the terms and eligibility requirements of those plans.

401(k) Plan. The NEOs are eligible to participate in a tax qualified 401(k) defined contribution plan to the same extent as all of our other employees. In 2019, we made a fully vested matching contribution on behalf of each of the 401(k) plan's participants up to 5% of such participant's eligible salary for the year.

Health Savings Account ("HSA") Program. The NEOs are eligible to participate in a tax qualified health savings account (“HSA”) if they are enrolled in the available high-deductible health plan. The HSA is a tax-free savings account owned by an individual and can be used to pay for current or future qualified medical expenses. Participants determine how much to contribute, when and how to spend the money on eligible medical expenses, and how to invest the balance. The balance remains in the account and is not subject to forfeiture. The Partnership makes annual contributions to all HSA-eligible employees who enroll in and contribute to an HSA. In 2019, Summit Investments made tax-free HSA contributions of $1,680 to Mr. Graves, $1,575 to Mr. Stratton and $1,995 to Ms. Matthews.

Deferred Compensation Plan. Effective July 1, 2013, the Board approved a Deferred Compensation Plan (the “DCP”), which is a defined contribution supplemental executive retirement plan established to attract and retain key employees and directors by providing participants with an opportunity to defer receipt of a portion of their salary, bonus and other specified compensation. The DCP is an unfunded, nonqualified plan that provides each participant in the plan with benefits based on the participant’s notional account balance at the time of retirement or termination.  Each participant allocates deferrals among designated mutual fund investments to serve as indices for the purpose of determining notional investment gains and losses to each participant’s account.

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Deferrals of SMLP LTIP grants and other equity-based awards are allocated to the Summit Midstream Partners, LP Unit Fund (the “Unit Fund”). The Unit Fund consists of notional common units in SMLP, with each unit approximating the value of one common unit of SMLP. The distribution equivalent rights associated with any SMLP LTIP grant may be allocated to any available investment option, other than the Unit Fund.

The DCP is filed as Exhibit 4.3 to the Partnership’s Form S-8 Registration Statement dated June 28, 2013.

Additional Benefits. Pursuant to the terms of their employment agreements:

 

All NEOs are entitled to reimbursement for tax preparation and advisory services expenses of up to $12,000 per year.

 

Mr. Deneke is entitled to be reimbursed up to $15,000 per year for annual international or local chapter dues associated with his membership in YPO.

Expenditures for these benefits are included as “All Other Compensation” in the Summary Compensation Table and further described in the table entitled “All Other Compensation” below.

Employment and Severance Arrangements.  

Employment Agreements. Our NEOs each have employment agreements with Summit Investments (the “Company”). Elements of the NEOs’ total direct compensation are subject to periodic review and may be adjusted accordingly by the Compensation Committee.

Mr. Deneke’s employment agreement, which has an effective date of September 16, 2019, has an initial term that expires on September 16, 2021, and is then automatically extended for successive one-year periods, unless either party gives notice of non-extension to the other no later than 30 days prior to the expiration of the then-applicable term. Mr. Deneke’s employment agreement provides for an annual base salary of $600,000, and a performance-based bonus ranging from 0% to 300% of base salary, with a target of 150% of base salary. Mr. Deneke is entitled to receive a prorated annual bonus (based on target) if his employment is terminated by Mr. Deneke with good reason, or by the Company without cause or as a result of a non-extension of the term, or due to death or disability. In addition, Mr. Deneke’s employment agreement also provides for reimbursement of certain business expenses incurred in connection with his employment, including company-paid tax preparation and advisory services of up to $12,000 per year and YPO membership dues of up to $15,000 per year.

Mr. Deneke’s employment agreement provides for a cash severance payment upon a termination resulting from a non-extension of the term by the Company, by the Company without cause or by Mr. Deneke for good reason, which is defined generally as the officer's termination of employment within two years after the occurrence of (i) a material diminution in Mr. Deneke’s authority, duties or responsibilities, (ii) a material diminution in the aggregated total of Mr. Deneke’s base salary, target bonus (as a percentage of base salary) or Annual LTIP Target (as that term is defined in the agreement), (iii) a material change in the geographic location at which Mr. Deneke must perform his services under the agreement, (iv) a change in Mr. Deneke’s reporting relationship resulting in Mr. Deneke no longer reporting directly to the Board of Directors of the Company or the General Partner, or (v) any other action or inaction that constitutes a material breach of the employment agreement by the Company (each a "Qualifying Termination"). In the event of a Qualifying Termination, Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year.

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Following any termination of employment other than one resulting from non-extension of the term, his employment agreement provides that Mr. Deneke will be subject to a post-termination non-competition covenant through the severance period, and, following any termination of employment, Mr. Deneke will be subject to a one-year post-termination non-solicitation covenant. If Mr. Deneke’s employment terminates as a result of a non-extension of the term, the Company may choose to subject him to a non-competition covenant for up to one year post-termination. If the Company exercises this “noncompete option” following a non-extension of term by Mr. Deneke, then Mr. Deneke would be entitled to a severance payment in an amount equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by the Company) and the denominator of which is 365. In this case, the severance payment will be payable in equal installments over the restricted period. Following any termination of employment, the Company has agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage.

Mr. Deneke’s employment agreement also provides that all equity awards granted to him under the LTIP and held by him as of immediately prior to a change in control of the Company will become fully vested immediately prior to the change in control.

Mr. Deneke’s employment agreement provides that, if any portion of the payments or benefits provided to Mr. Deneke would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code, then the payments and benefits will be reduced if such reduction would result in a greater after-tax payment to Mr. Deneke.

Additionally, as an inducement to accept the position of President and Chief Executive Officer of the Company, at the beginning of his employment term, Mr. Deneke received a one-time grant of phantom units valued at $4,000,000, pursuant to the Award Agreement. Subject to the terms and conditions of the Award Agreement, the underlying phantom units will vest ratably over a three-year period, and are entitled to distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date. Furthermore, the phantom units will be subject to accelerated vesting on the occurrence of any of the following events: (i) a termination of Mr. Deneke’s employment other than for cause, (ii) a termination of employment by Mr. Deneke for good reason (as that term is defined in Mr. Deneke’s employment agreement), (iii) a termination of Mr. Deneke’s employment by reason of death or disability or (iv) a Change in Control (as defined in the Award Agreement).

The remaining NEOs’ employment agreements (other than Mr. Newby’s) are substantially the same as Mr. Deneke’s, except for the following:

 

Each of the other NEOs is entitled to a severance payment in the event of a Qualifying Termination equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year.

 

Each of the other NEOs is entitled to a severance payment in the event the Company exercises the “noncompete option” following a non-extension of the term by the NEO equal to the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year.

 

Each of the other NEOs is entitled to a performance-based bonus ranging from 0% to 200% of base salary, with a target of 100% of base salary.

 

The other NEOs are not entitled to be reimbursed for membership dues or the cost of an annual executive physical.

 

Mr. Stratton’s base salary is $350,000, and the initial term of his employment agreement ends on March 31, 2021.

 

Mr. Degeyter’s base salary is $380,000, and the initial term of his employment agreement ends on March 1, 2020.

 

Mr. Graves’ base salary is $400,000, and the initial term of his employment agreement ended on March 1, 2019.

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Mr. Mallett’s base salary is $400,000, and the initial term of his employment agreement ends on March 1, 2020.

 

Ms. Matthews’ base salary is $300,000 and the initial term of her employment agreement ends on March 31, 2021.

 

Additionally, as an inducement to accept the position of Chief Operations Officer of the Company, on December 1, 2015, Mr. Mallett received a one-time grant of phantom units valued at $1,600,000, pursuant to a standalone phantom unit award agreement. The phantom units vested ratably over a three-year period, which concluded on December 1, 2018.

Mr. Newby’s employment agreement is substantially similar to Mr. Deneke’s except for the following:

 

It provides for a severance payment in the event the Company exercises the “noncompete option” following a non-extension of the term by Mr. Newby equal to the sum of his annual base salary and his or her annual bonus payable in respect of the immediately preceding year.

 

It did not provide for a one-time grant of phantom units as an inducement to accept the position of President and Chief Executive Officer.

Pursuant to his employment agreement, Mr. Newby was paid a cash severance payment upon his termination effective February 28, 2019, which was a “Qualifying Termination” under his employment agreement. In addition, Mr. Newby’s outstanding equity awards vested upon his termination.

Retention Bonus Agreements.

Effective June 7, 2019, Summit Investments, the General Partner, and SMLP jointly entered into retention bonus agreements with certain NEOs for the amounts indicated below:

Mr. Mallett: $420,000

Mr. Degeyter: $400,000

Mr. Graves: $400,000

Mr. Stratton: $365,000

Ms. Matthews: $365,000

The agreements provide for a cash payment “Retention Bonus” upon the earlier of a termination without cause or a change in control (as those terms are defined in the executive’s employment agreement). The agreements terminate if the executive officer continues to be employed and a change in control has not occurred on or prior to December 31, 2020, provided that the termination date may be extended to December 31, 2021.

Risk Assessment Relative to Compensation Programs.  The Compensation Committee manages risk as it relates to our compensation plans, programs and structure (collectively, our “compensation practices”). The Compensation Committee meets with management to review whether any aspect of our compensation practices creates incentives for our employees to take inappropriate risks that could materially adversely affect the Partnership. Accordingly, we believe that the compensation practices for our NEOs and other employees are appropriately structured and do not pose a material risk to the Partnership. We believe these compensation practices are designed and implemented in a manner that does not promote excessive risk-taking that could damage the value of the Partnership or provide compensatory rewards for inappropriate decisions or behavior.

Compensation Committee Report.  The Compensation Committee has reviewed and discussed this CD&A with our management and, based on such review and discussion, has recommended to the Board that the CD&A be included in the Annual Report on Form 10-K.

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Summary Compensation Table for 2019, 2018 and 2017

The following table sets forth certain information with respect to the compensation paid to our NEOs for the years ended December 31, 2019, 2018 and 2017 and allocated to us by our General Partner. Under the terms of our Partnership Agreement, our General Partner determines the portion of the NEOs' compensation that is allocated to us. For a discussion of the cost allocation methodology, please refer to "Agreements with Affiliates—Reimbursement of Expenses from General Partner" in Item 13. Certain Relationships and Related Transactions, and Director Independence.

 

Name and Principal Position

 

Year

 

 

Salary ($) (1)

 

 

Bonus ($)

 

 

Equity Awards

($) (2)

 

 

Non-Equity Incentive Plan Compensation ($) (3)

 

 

All Other Compensation ($) (4)

 

 

Total ($)

 

Heath Deneke (5)

 

 

2019

 

 

 

161,538

 

 

 

 

 

 

4,000,000

 

 

 

300,000

 

 

 

28,822

 

 

 

4,490,360

 

President and Chief Executive Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Steven J. Newby (6)

 

 

2019

 

 

 

89,328

 

 

 

 

 

 

 

 

 

81,614

 

 

 

1,713,791

 

 

 

1,884,733

 

President and Chief Executive Officer (former)

 

 

2018

 

 

 

459,000

 

 

 

 

 

 

1,550,000

 

 

 

688,500

 

 

 

34,487

 

 

 

2,731,987

 

 

 

 

2017

 

 

 

540,000

 

 

 

 

 

 

1,950,000

 

 

 

769,500

 

 

 

36,918

 

 

 

3,296,418

 

Marc D. Stratton (7)

 

 

2019

 

 

 

262,500

 

 

 

 

 

 

768,500

 

 

 

170,625

 

 

 

28,800

 

 

 

1,230,425

 

Executive Vice President and Chief Financial Officer

 

 

2018

 

 

 

231,782

 

 

 

 

 

 

225,000

 

 

 

254,625

 

 

 

31,700

 

 

 

743,107

 

Brock M. Degeyter

 

 

2019

 

 

 

266,000

 

 

 

 

 

 

818,500

 

 

 

172,900

 

 

 

26,938

 

 

 

1,284,338

 

Executive Vice President, General Counsel and Chief Compliance Officer

 

 

2018

 

 

 

335,700

 

 

 

 

 

 

625,000

 

 

 

352,800

 

 

 

33,980

 

 

 

1,347,480

 

 

 

 

2017

 

 

 

346,750

 

 

 

 

 

 

700,000

 

 

 

342,000

 

 

 

34,983

 

 

 

1,423,733

 

Brad N. Graves

 

 

2019

 

 

 

320,000

 

 

 

 

 

 

600,000

 

 

 

320,000

 

 

 

32,100

 

 

 

1,272,100

 

Executive Vice President and Chief Commercial Officer

 

 

2018

 

 

 

368,150

 

 

 

 

 

 

625,000

 

 

 

368,150

 

 

 

38,114

 

 

 

1,399,414

 

 

 

 

2017

 

 

 

390,000

 

 

 

 

 

 

700,000

 

 

 

375,000

 

 

 

39,438

 

 

 

1,504,438

 

Leonard W. Mallett (8)

 

 

2019

 

 

 

350,000

 

 

 

87,500

 

 

 

843,500

 

 

 

227,500

 

 

 

12,895

 

 

 

1,521,395

 

Executive Vice President and Chief Operations Officer

 

 

2018

 

 

 

364,800

 

 

 

 

 

 

625,000

 

 

 

364,800

 

 

 

13,773

 

 

 

1,368,373

 

 

 

 

2017

 

 

 

375,000

 

 

 

 

 

 

700,000

 

 

 

375,000

 

 

 

14,624

 

 

 

1,464,624

 

Louise E. Matthews (9)

 

 

2019

 

 

 

285,000

 

 

 

 

 

 

693,500

 

 

 

185,250

 

 

 

35,197

 

 

 

1,198,947

 

Executive Vice President and Chief Administration Officer

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1) Amounts shown represent the portion of the NEO's base salary allocated to SMLP.

(2) Amounts shown reflect the grant date fair value of the phantom unit awards granted to the NEOs in 2019, 2018 and 2017, respectively, in accordance with FASB Accounting Standards Codification Topic 718, Compensation—Stock Compensation ("FASB ASC Topic 718"). For the assumptions made in valuing these awards, see Note 14 to the consolidated financial statements. For additional information, please refer to "Components of Executive Compensation—Long-Term Equity-Based Compensation Awards" above.

(3) Amounts shown represent the incentive bonus earned under our annual incentive bonus program in the fiscal year indicated but paid in the following fiscal year. The amounts shown represent that portion of the NEO's annual bonus that has been allocated to SMLP.

(4) The table below presents the components of "All Other Compensation" allocated to SMLP for each NEO for the fiscal year ended December 31, 2019. For additional information, please see "Components of Executive Compensation—Retirement, Health and Welfare and Additional Benefits" above.

(5) Mr. Deneke began his employment with the Company effective September 16, 2019.

(6) Mr. Newby resigned from his position as our President and Chief Executive Officer effective February 21, 2019 and his employment terminated on February 28, 2019. The portion of the severance payment made to Mr. Newby in 2019 is included in the “All Other Compensation” column.

(7) Mr. Stratton was appointed Executive Vice President and Chief Financial Officer effective December 7, 2018. Mr. Stratton was not an NEO prior to his appointment.

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(8) In addition to his equity and non-equity incentive plan awards, Mr. Mallett received a one-time cash bonus of $100,000 relating to his service as our President and Chief Executive Officer during the period between the resignation of Mr. Newby and the appointment of Mr. Deneke. A portion of this bonus has been allocated to us and is included in the “Bonus” column.

(9) Ms. Matthews was not an NEO before 2019.

Pay Ratio Disclosure

The following is a reasonable estimate, prepared under applicable SEC rules, of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of our other employees. Although we previously identified our median employee on December 29, 2017, due to a change in our employee population that we reasonably believe would result in a significant change to our pay ratio disclosure, we identified a new median employee in 2019. For 2019, we determined our median employee by ranking our employees (other than the CEO) employed as of December 31, 2019 (the “determination date”) by the sum of each employee’s annualized base salary, his or her actual cash bonus received in 2019 for 2018 performance, and his or her actual overtime pay received in 2019. In annualizing each employee’s base salary, we used each employee’s base salary rate as of the determination date. We made no full-time equivalent adjustment for any employee, we had no temporary or seasonal workers as of the determination date, and we made no cost-of-living adjustments. The annual total compensation of our median employee (other than the CEO) for 2019 was $91,403. To determine the annual total compensation of our CEO for purposes of this disclosure, we chose the person who was serving as CEO as of the determination date and used the total compensation he received in 2019 as set forth in the Summary Compensation Table above except that we annualized his compensation. Accordingly, for purposes of this disclosure, we determined that the CEO’s annual total compensation for 2019 that was allocated to us by our General Partner was $5,235,055. Based on the foregoing, our estimate of the ratio of the annual total compensation of our CEO to the median of the annual total compensation of all other employees was 57.3 to 1. Given the different methodologies that various public companies will use to determine an estimated pay ratio, our estimated pay ratio should not be used as a basis for comparison with ratios disclosed by other companies.

All Other Compensation.  The following table sets forth information concerning all other compensation paid to our NEOs in fiscal 2019 and allocated to us by our General Partner.

 

Name

 

Medical Insurance Premium ($)

 

 

Individual Tax Preparation ($)

 

 

Health Savings Account (HSA) Employer Contributions ($)

 

 

401(k) Plan Employer Contributions ($)

 

 

Membership Dues ($)

 

 

Severance Paid in 2019 ($)

 

 

Total ($)

 

Heath Deneke

 

 

5,640

 

 

 

3,025

 

 

 

 

 

 

8,077

 

 

 

12,080

 

 

 

 

 

 

28,822

 

Steven  J. Newby

 

 

11,706

 

 

 

 

 

 

 

 

 

7,700

 

 

 

 

 

 

1,694,385

 

 

 

1,713,791

 

Marc D. Stratton

 

 

15,712

 

 

 

1,013

 

 

 

1,575

 

 

 

10,500

 

 

 

 

 

 

 

 

 

28,800

 

Brock M. Degeyter

 

 

14,618

 

 

 

2,520

 

 

 

 

 

 

9,800

 

 

 

 

 

 

 

 

 

26,938

 

Brad N. Graves

 

 

16,760

 

 

 

2,460

 

 

 

1,680

 

 

 

11,200

 

 

 

 

 

 

 

 

 

32,100

 

Leonard W. Mallett

 

 

12,895

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

12,895

 

Louise E. Matthews

 

 

19,902

 

 

 

 

 

 

1,995

 

 

 

13,300

 

 

 

 

 

 

 

 

 

35,197

 

 

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Grants of Plan-Based Awards in 2019.  The following table sets forth information concerning annual incentive awards and phantom unit awards granted to our NEOs in fiscal 2019.

 

 

 

 

 

Estimated Possible Payouts Under Non-Equity Incentive Plan Awards (2)

 

 

All Other Stock Awards: Number of Shares of Stocks or Units (3)

 

 

Grant Date Fair Value of Stock and Options Awards (4)

 

Name (1)

 

Grant Date

 

Threshold ($)

 

Target ($)

 

 

Maximum ($)

 

 

(#)

 

 

($)

 

Heath Deneke

 

N/A

 

N/A

 

 

900,000

 

 

 

1,800,000

 

 

 

 

 

 

 

 

 

 

 

9/16/2019

 

 

 

 

 

 

 

 

 

 

 

 

772,200

 

 

 

4,000,000

 

Marc D. Stratton

 

N/A

 

N/A

 

 

350,000

 

 

 

700,000

 

 

 

 

 

 

 

 

 

 

 

3/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

58,793

 

 

 

575,000

 

 

 

11/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

50,000

 

 

 

193,500

 

Brock M. Degeyter

 

N/A

 

N/A

 

 

380,000

 

 

 

760,000

 

 

 

 

 

 

 

 

 

 

 

3/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

63,905

 

 

 

625,000

 

 

 

11/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

50,000

 

 

 

193,500

 

Brad N. Graves

 

N/A

 

N/A

 

 

400,000

 

 

 

800,000

 

 

 

 

 

 

 

 

 

 

 

3/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

61,349

 

 

 

600,000

 

Leonard W. Mallett

 

N/A

 

N/A

 

 

400,000

 

 

 

800,000

 

 

 

 

 

 

 

 

 

 

 

3/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

66,462

 

 

 

650,000

 

 

 

11/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

50,000

 

 

 

193,500

 

Louise E. Matthews

 

N/A

 

N/A

 

 

300,000

 

 

 

600,000

 

 

 

 

 

 

 

 

 

 

 

3/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

51,124

 

 

 

500,000

 

 

 

11/15/2019

 

 

 

 

 

 

 

 

 

 

 

 

50,000

 

 

 

193,500

 

 

(1) Mr. Newby is omitted from this table. Due to his termination on February 28, 2019, Mr. Newby received no grants of phantom unit awards and did not participate in the non-equity incentive program in 2019.

(2) Represents annual incentive opportunities that may be awarded pursuant to our annual incentive program for the year ended December 31, 2019 with payment based upon our achievement of pre-established performance goals and other factors. For additional information, please see "Components of Executive Compensation—Annual Incentive Compensation" above.

(3) Represents grants of phantom units with distribution equivalent rights under the SMLP LTIP. For additional information, please see "Components of Executive Compensation—Long-Term Equity-Based Compensation Awards" above.

(4) Amounts shown represent the fair value of the award on the date of the grant, in accordance with FASB ASC Topic 718. For the assumptions made in valuing these awards, see Note 14 to the consolidated financial statements.

Narrative Disclosure to the Summary Compensation Table and Grants of the Plan-Based Awards Table.  A description of material factors necessary to understand the information disclosed in the tables above with respect to salaries, bonuses, equity awards, non-equity incentive plan compensation and all other compensation can be found in the CD&A that precedes these tables.

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Outstanding Equity Awards at December 31, 2019.  The following table presents information regarding the outstanding equity awards held by our NEOs at December 31, 2019.

 

 

 

 

 

Unit Awards

 

Name (1)

 

Grant Date

 

Number of Unearned Phantom Units That Have Not Vested (#) (2)

 

 

Market Value of Unearned Phantom Units That Have Not Vested ($) (3)

 

Heath Deneke

 

9/16/2019

 

 

772,200

 

 

 

2,555,982

 

Marc D. Stratton

 

11/15/2019

 

 

50,000

 

 

 

165,500

 

 

 

3/15/2019

 

 

58,793

 

 

 

194,605

 

 

 

3/15/2018

 

 

9,836

 

 

 

32,557

 

 

 

3/15/2017

 

 

3,111

 

 

 

10,297

 

Brock M. Degeyter

 

11/15/2019

 

 

50,000

 

 

 

165,500

 

 

 

3/15/2019

 

 

63,905

 

 

 

211,526

 

 

 

3/15/2018

 

 

27,322

 

 

 

90,436

 

 

 

3/15/2017

 

 

10,370

 

 

 

34,325

 

Brad N. Graves

 

3/15/2019

 

 

61,349

 

 

 

203,065

 

 

 

3/15/2018

 

 

27,322

 

 

 

90,436

 

 

 

3/15/2017

 

 

10,370

 

 

 

34,325

 

Leonard W. Mallett

 

11/15/2019

 

 

50,000

 

 

 

165,500

 

 

 

3/15/2019

 

 

66,462

 

 

 

219,989

 

 

 

3/15/2018

 

 

27,322

 

 

 

90,436

 

 

 

3/15/2017

 

 

10,370

 

 

 

34,325

 

Louise E. Matthews

 

11/15/2019

 

 

50,000

 

 

 

165,500

 

 

 

3/15/2019

 

 

51,124

 

 

 

169,220

 

 

 

3/15/2018

 

 

9,398

 

 

 

31,107

 

 

 

3/15/2017

 

 

2,962

 

 

 

9,804

 

 

(1) Mr. Newby is omitted from this table because his outstanding equity awards vested upon his termination without cause effective February 28, 2019.

(2) Except for phantom units granted to certain NEOs on November 15, 2019, which vest in their entirety on the third anniversary of the grant date, phantom units granted to the NEOs vest ratably over a three-year period with the first tranche scheduled to vest on the first anniversary of the grant date, subject to continued employment, and accelerated vesting as provided in the applicable award agreement. The NEOs also receive distribution equivalent rights for each phantom unit, providing for a lump sum payment equal to the accrued distributions from the grant date of the phantom units to be paid in cash upon the vesting date.

(3) Amounts were calculated using the closing price of SMLP's publicly traded common units on December 31, 2019.

Phantom Units Vested.  The following table represents information regarding the vesting of phantom units during the year ended December 31, 2019 with respect to our NEOs.

 

 

 

Phantom Unit Awards

 

Name

 

Number of Phantom Units  Vested (#) (1)

 

 

Value Realized on Vesting ($) (1)

 

Heath Deneke

 

 

 

 

 

 

Steven J. Newby

 

 

198,777

 

 

 

2,858,293

 

Marc D. Stratton

 

 

12,302

 

 

 

175,419

 

Brock M. Degeyter

 

 

38,650

 

 

 

557,990

 

Brad N. Graves

 

 

38,650

 

 

 

557,990

 

Leonard W. Mallett

 

 

37,526

 

 

 

539,242

 

Louise E. Matthews

 

 

11,599

 

 

 

165,036

 

___________

(1) For NEOs other than Mr. Newby, the amounts represent the number and value of the phantom units that vested on March 15, 2019, plus the distribution equivalent rights earned in tandem. The value of the phantom units that vested on March 15, 2019 was calculated using the closing price of SMLP's publicly traded common units as of March 14, 2019, the trading day immediately prior to vesting. Mr. Newby’s amounts represent the number and value of the phantom units that vested upon his termination effective

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February 28, 2019, plus the distribution equivalent rights earned in tandem. The value of Mr. Newby’s phantom units that vested on February 28, 2019 was calculated using the closing price of SMLP’s units as of February 27, 2019.

Pension Benefits.  Currently, our General Partner does not sponsor or maintain a pension or defined benefit program for our NEOs. This policy may change in the future.

Nonqualified Deferred Compensation Table for 2019.  The following table represents information regarding the nonqualified deferred compensation of our NEOs for the year ended December 31, 2019.

 

Name

 

Executive Contributions in Last Fiscal Year ($) (1)

 

 

Registrant Contributions in Last Fiscal Year ($)

 

 

Aggregate Earnings in Last Fiscal Year ($)

 

 

Aggregate Withdrawals / Distributions ($)

 

 

Aggregate Balance at Last Fiscal Year-End ($)

 

Steven J. Newby

 

 

124,422

 

 

 

 

 

 

(440,052

)

 

 

(522,332

)

 

 

918,054

 

Marc D. Stratton

 

 

 

 

 

 

 

 

8,009

 

 

 

 

 

 

41,551

 

Brad N. Graves

 

 

3,898

 

 

 

 

 

 

17,139

 

 

 

 

 

 

214,594

 

 

(1) Messrs. Newby and Graves’ executive contributions are comprised of quarterly distributions on previously deferred LTIP units. For additional information, see "Components of Executive Compensation—Retirement, Health and Welfare and Additional Benefits" above.

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Potential Payments upon Termination or Change in Control.  The following table sets forth information concerning potential amounts payable to the NEOs upon termination of employment under various circumstances, and upon a change in control, if such event took place on December 31, 2019.

 

Name and Principal Position

 

Triggering Event

 

Salary ($)

 

 

Bonus ($) (1)

 

 

Pro-Rata Bonus ($)

 

 

Health Benefits ($)

 

 

Acceleration of Unvested Equity ($) (2)

 

 

Total ($)

 

Heath Deneke

President and Chief Executive Officer (3)

 

Termination by Reason of Death or Disability

 

 

 

 

 

 

 

 

263,836

 

 

 

22,407

 

 

 

2,777,990

 

 

 

3,064,233

 

 

 

Termination Without Cause

 

 

1,500,000

 

 

 

2,250,000

 

 

 

263,836

 

 

 

22,407

 

 

 

2,777,990

 

 

 

6,814,233

 

 

 

Resignation for Good Reason

 

 

1,500,000

 

 

 

2,250,000

 

 

 

263,836

 

 

 

22,407

 

 

 

2,777,990

 

 

 

6,814,233

 

 

 

Nonextension of Term by Company

 

 

1,500,000

 

 

 

2,250,000

 

 

 

263,836

 

 

 

22,407

 

 

 

2,777,990

 

 

 

6,814,233

 

 

 

Nonextension of Term by Executive, Company Exercises Noncompete

 

 

1,500,000

 

 

 

2,250,000

 

 

 

 

 

 

22,407

 

 

 

 

 

 

3,772,407

 

 

 

Change in Control (4)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

2,777,990

 

 

 

2,777,990

 

Marc D. Stratton

Executive Vice President and Chief Financial Officer (5)

 

Termination by Reason of Death or Disability

 

 

 

 

 

 

 

 

350,000

 

 

 

22,407

 

 

 

501,769

 

 

 

874,176

 

 

 

Termination Without Cause

 

 

525,000

 

 

 

801,500

 

 

 

350,000

 

 

 

22,407

 

 

 

501,769

 

 

 

2,200,676

 

 

 

Resignation for Good Reason

 

 

525,000

 

 

 

436,500

 

 

 

350,000

 

 

 

22,407

 

 

 

501,769

 

 

 

1,835,676

 

 

 

Nonextension of Term by Company

 

 

525,000

 

 

 

436,500

 

 

 

350,000

 

 

 

22,407

 

 

 

501,769

 

 

 

1,835,676

 

 

 

Change in Control (4)

 

 

 

 

 

365,000

 

 

 

 

 

 

 

 

 

501,769

 

 

 

866,769

 

 

 

Nonextension of Term by Executive, Company Exercises Noncompete

 

 

350,000

 

 

 

291,000

 

 

 

 

 

 

22,407

 

 

 

 

 

 

663,407

 

Brock M. Degeyter

Executive Vice President, General Counsel and Chief Compliance Officer (5)

 

Termination by Reason of Death or Disability

 

 

 

 

 

 

 

 

380,000

 

 

 

22,341

 

 

 

699,956

 

 

 

1,102,297

 

 

 

Termination Without Cause

 

 

570,000

 

 

 

988,000

 

 

 

380,000

 

 

 

22,341

 

 

 

699,956

 

 

 

2,660,297

 

 

 

Resignation for Good Reason

 

 

570,000

 

 

 

588,000

 

 

 

380,000

 

 

 

22,341

 

 

 

699,956

 

 

 

2,260,297

 

 

 

Nonextension of Term by Company

 

 

570,000

 

 

 

588,000

 

 

 

380,000

 

 

 

22,341

 

 

 

699,956

 

 

 

2,260,297

 

 

 

Change in Control (4)

 

 

 

 

 

400,000

 

 

 

 

 

 

 

 

 

699,956

 

 

 

1,099,956

 

 

 

Nonextension of Term by Executive, Company Exercises Noncompete

 

 

380,000

 

 

 

392,000

 

 

 

 

 

 

22,341

 

 

 

 

 

 

794,341

 

Leonard W. Mallett

Executive Vice President and Chief Operations Officer (5)

 

Termination by Reason of Death or Disability

 

 

 

 

 

 

 

 

400,000

 

 

 

15,285

 

 

 

710,625

 

 

 

1,125,910

 

 

 

Termination Without Cause

 

 

600,000

 

 

 

996,000

 

 

 

400,000

 

 

 

15,285

 

 

 

710,625

 

 

 

2,721,910

 

 

 

Resignation for Good Reason

 

 

600,000

 

 

 

576,000

 

 

 

400,000

 

 

 

15,285

 

 

 

710,625

 

 

 

2,301,910

 

 

 

Nonextension of Term by Company

 

 

600,000

 

 

 

576,000

 

 

 

400,000

 

 

 

15,285

 

 

 

710,625

 

 

 

2,301,910

 

 

 

Change in Control (4)

 

 

 

 

 

420,000

 

 

 

 

 

 

 

 

 

710,625

 

 

 

1,130,625

 

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Nonextension of Term by Executive, Company Exercises Noncompete

 

 

400,000

 

 

 

384,000

 

 

 

 

 

 

15,285

 

 

 

 

 

 

799,285

 

Louise E. Matthews

Executive Vice President and Chief Administration Officer (5)

 

Termination by Reason of Death or Disability

 

 

 

 

 

 

 

 

300,000

 

 

 

22,407

 

 

 

465,628

 

 

 

788,035

 

 

 

Termination Without Cause

 

 

450,000

 

 

 

747,500

 

 

 

300,000

 

 

 

22,407

 

 

 

465,628

 

 

 

1,985,535

 

 

 

Resignation for Good Reason

 

 

450,000

 

 

 

382,500

 

 

 

300,000

 

 

 

22,407

 

 

 

465,628

 

 

 

1,620,535

 

 

 

Nonextension of Term by Company

 

 

450,000

 

 

 

382,500

 

 

 

300,000

 

 

 

22,407

 

 

 

465,628

 

 

 

1,620,535

 

 

 

Change in Control (4)

 

 

 

 

 

365,000

 

 

 

 

 

 

 

 

 

465,628

 

 

 

830,628

 

 

 

Nonextension of Term by Executive, Company Exercises Noncompete

 

 

300,000

 

 

 

255,000

 

 

 

 

 

 

22,407

 

 

 

 

 

 

577,407

 

Steven J. Newby

Former President and Chief Executive Officer (6) (7)

 

Termination Without Cause

 

 

1,530,000

 

 

 

2,137,500

 

 

 

1,066,389

 

 

 

22,713

 

 

 

2,858,293

 

 

 

7,614,895

 

Brad N. Graves

Executive Vice President and Chief Commercial Officer (5) (7)

 

Termination Without Cause

 

 

600,000

 

 

 

997,000

 

 

 

400,000

 

 

 

22,407

 

 

 

494,079

 

 

 

2,513,486

 

___________

(1)

Where applicable, the amount includes the “Retention Bonus” payable to Messrs. Mallett, Degeyter, Graves, and Stratton upon a termination without cause or change in control. For more information see “Employment and Severance Arrangements; Retention Bonus Agreements” above.

(2)

Amounts represent the value of the phantom units that vest upon the occurrence of a triggering event plus the earned distribution equivalent rights that vest in tandem. The value of the phantom units was calculated using the closing price of SMLP's publicly traded common units on December 31, 2019.

(3)

Mr. Deneke’s employment agreement provides that upon termination of employment resulting from a non-extension of the term by Summit Investments, termination by Summit Investments without cause, or by Mr. Deneke’s resignation for good reason (each a "Qualifying Termination"), Mr. Deneke’s severance payment will be equal to two and one-half times the sum of his annual base salary and the higher of his target annual bonus payable in respect of the immediately preceding year and the annual bonus actually paid to him in respect of that year. Mr. Deneke is also entitled to receive a prorated annual bonus (based on target) if his employment is terminated by reason of death or disability or as a result of a Qualifying Termination. If Summit Investments exercises the “noncompete option” after Mr. Deneke elects not to extend the term, then Mr. Deneke is entitled to a severance payment in an amount equal to the two and one-half times the sum of his annual base salary and the higher of the target annual bonus payable or the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by Summit Investments) and the denominator of which is 365. Any unvested equity awards granted to Mr. Deneke will immediately vest upon a Qualifying Termination, termination by reason of death or disability, or a change in control. If any portion of the payments or benefits provided to Mr. Deneke in connection with a change in control become subject to the excise tax under Section 4999 of the Internal Revenue Code, then the payments and benefits will be reduced to the extent such reduction would result in a greater after-tax benefit to Mr. Deneke. Following any termination of employment, Summit Investments has agreed to pay the out-of-pocket premium cost to continue Mr. Deneke’s medical and dental coverage for a period not to exceed 18 months, with such coverage terminating if any new employer provides benefits coverage.

(4)

Single-trigger event without a qualifying termination of employment.

(5)

Mr. Stratton’s, Mr. Degeyter’s, Mr. Mallett’s, Mr. Graves’ and Ms. Matthews’ employment agreements are substantially identical to Mr. Deneke’s with respect to potential payments upon termination or a change in control, except that (i) in the event of a Qualifying Termination, each of these NEOs is entitled to receive a severance payment equal to one and one-half times the sum of his or her annual base salary and his or her annual bonus payable in respect of the immediately preceding year; and (ii) in the event Summit Investments exercises the “noncompete option” after any such NEO elects not to extend the term, then the NEO is entitled to a severance payment equal to the sum of his or her annual base salary and the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date

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of termination through the expiration of the restricted period (as elected by Summit Investments) and the denominator of which is 365.

(6)

Mr. Newby’s employment agreement is substantially identical to Mr. Deneke’s with respect to potential payments upon termination or a change in control, except that in the event Summit Investments exercises the “noncompete option” after Mr. Newby elects not to extend the term, then he is entitled to a severance payment equal to the sum of his annual base salary and the bonus actually paid in respect of the preceding year, multiplied by a fraction, the numerator of which is equal to the number of days from the date of termination through the expiration of the restricted period (as elected by Summit Investments) and the denominator of which is 365.

(7)

Both Mr. Newby and Graves were terminated without cause in 2019. Accordingly, disclosure is limited to the triggering event that actually occurred. In Mr. Newby’s case, the amounts reflect actual amounts.

Compensation Committee Report

The Compensation Committee provides oversight, administers and makes decisions regarding our compensation policies and plans. Additionally, the Compensation Committee generally reviews and discusses the Compensation Discussion and Analysis with senior management of our General Partner as a part of our governance practices. Based on this review and discussion, the Compensation Committee has recommended to the Board of Directors of our General Partner that the Compensation Discussion and Analysis be included in this report for filing with the SEC.

.

Members of the Compensation Committee of Summit Midstream GP, LLC

Thomas K. Lane

 

Jeffrey R. Spinner

 

Robert M. Wohleber

 

Director Compensation

In 2019, under the director compensation plan, the independent directors, which include Messrs. Peters, Wohleber, and Jacobe, each received the following:

 

an annual cash retainer of $80,000; and

 

an annual award of common units with a grant date fair value of approximately $80,000.

In addition, under the director compensation plan, the independent directors receive the following for their respective service on our Board's committees:

 

the chairman of the Audit Committee receives an additional annual retainer of $15,000;

 

the chairman of the Conflicts Committee receives an additional annual retainer of $10,000; and

 

each independent member of any committee (other than the chairman) received an additional annual retainer of $5,000.

Messrs. Peters and Wohleber were paid their compensation in March 2019, whereas Mr. Jacobe was paid upon the commencement of his service on the Board in April 2019.

In addition to their regular compensation described above, the independent directors received the following additional fees for the increased time and effort they expended as chairperson and members, respectively, of the Conflicts Committee, in connection with the review of certain major transactions in 2019:

 

$25,000 to Mr. Wohleber and $20,000 to Mr. Peters for their work on the Equity Restructuring;

 

$20,000 to Mr. Wohleber and $15,000 to Messrs. Peters and Jacobe for their work on the DPPO partial prepayment transaction; and

 

$15,000 to Messrs. Wohleber and Peters for their work relating to certain additional contemplated transactions.

Board members are reconsidered for appointment on the one-year anniversary of their most recent appointment.

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We reimburse all directors, except for employees of Energy Capital Partners for travel and other related expenses in connection with attending board and committee meetings and board-related activities. We do not compensate employees of the Partnership or Energy Capital Partners for their services as directors.

The following table shows the compensation paid, including amounts deferred, under our director compensation plan in 2019.

 

Name

 

Fees earned or paid in cash ($)

 

 

Other fees ($)

 

 

Unit awards

($) (1)

 

 

Compensation deferred ($) (2)

 

 

Total ($)

 

Matthew F. Delaney

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Lee Jacobe

 

 

105,000

 

 

 

 

 

 

80,000

 

 

 

 

 

 

185,000

 

Peter Labbat

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Thomas K. Lane

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Heath Deneke

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Jerry L. Peters

 

 

150,000

 

 

 

 

 

 

80,000

 

 

 

 

 

 

230,000

 

Jeffrey R. Spinner

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Robert M. Wohleber

 

 

160,000

 

 

 

 

 

 

80,000

 

 

 

 

 

 

240,000

 

 

(1) Amount shown represents the grant date fair value of the unit awards as determined in accordance with GAAP. These unit awards were fully vested on the grant date.

(2) In 2019, no director elected to defer any portion of his compensation related to Board committee service.

Compensation Committee Interlocks and Insider Participation

Our Compensation Committee consists of Mr. Lane, Mr. Spinner and Mr. Wohleber. Although our common units are listed on the NYSE, we have taken advantage of the “Limited Partnership” exemption to the NYSE rule that would otherwise require listed companies to have an independent compensation committee with a written charter. During 2019, no member of the Compensation Committee was an executive officer of another entity on whose compensation committee or board of directors any executive officer of Summit Investments (and in connection therewith, SMLP) served. During 2019, no director was an executive officer of another entity on whose compensation committee any executive officer of Summit Investments (and in connection therewith, SMLP) served.

Our CEO participated in his capacity as a director in the deliberations of the Board of Directors concerning named executive officer compensation and made recommendations to the Compensation Committee regarding named executive officer compensation but abstained from any decisions regarding his compensation. Also, Mr. Lane and Mr. Spinner were selected to serve on the Compensation Committee due to their affiliations with Energy Capital Partners, which controls our General Partner.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The following table sets forth certain information regarding the beneficial ownership of our common units of:

 

each person who is known to us to beneficially own 5% or more of such units to be outstanding (based solely on Schedules 13D and 13G filed with the SEC prior to February 18, 2020);

 

our General Partner;

 

each of the directors and NEOs of our General Partner; and

 

all of the directors and executive officers of our General Partner as a group.

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All information with respect to beneficial ownership has been furnished by the respective directors, officers or 5% or more unitholders as the case may be. The amounts and percentage of units beneficially owned are reported on the basis of regulations of the SEC governing the determination of beneficial ownership of securities. Under the rules of the SEC, a person is deemed to be a beneficial owner of a security if that person has or shares voting power, which includes the power to vote or to direct the voting of such security, or investment power, which includes the power to dispose of or to direct the disposition of such security.

In computing the number of common units beneficially owned by a person and the percentage ownership of that person, common units that a person has the right to acquire upon the vesting of phantom units where the units are issuable within 60 days of February 18, 2020, if any, are deemed outstanding, but are not deemed outstanding for computing the percentage ownership of any other person. The percentage of units beneficially owned is based on a total of 93,613,194 common limited partner units outstanding as of February 18, 2020.

Except as indicated by footnote, the persons named in the following table have sole voting and investment power with respect to all units shown as beneficially owned by them, subject to community property laws where applicable.

Name of Beneficial Owner

 

Common Units Beneficially Owned

 

 

Percentage of Common Units Beneficially Owned

 

Summit Investments (1) (2) (3)

 

 

45,318,866

 

 

 

48.4

%

SMP Holdings (2) (3) (4)

 

 

45,318,866

 

 

 

48.4

%

Energy Capital Partners II, LLC (1) (3) (5) (6)

 

 

51,234,693

 

 

 

54.7

%

SMLP Holdings, LLC (5) (6)

 

 

5,915,827

 

 

 

6.3

%

Invesco Ltd. (7)

 

 

13,906,836

 

 

 

14.9

%

Steven J. Newby (2) (9)

 

 

285,879

 

 

*

 

J. Heath Deneke (2) (8)

 

 

 

 

 

 

 

Brock M. Degeyter (2) (8)

 

 

135,327

 

 

*

 

Brad N. Graves (2) (8) (9)

 

 

173,916

 

 

*

 

Leonard W. Mallett (2) (8)

 

 

194,319

 

 

*

 

Louise Matthews (2)

 

 

50,416

 

 

 

 

 

Marc D. Stratton (2) (8)

 

 

60,174

 

 

*

 

Matthew F. Delaney (5)

 

 

 

 

*

 

Peter Labbat (5)

 

 

20,000

 

 

*

 

Thomas K. Lane (5) (10)

 

 

40,000

 

 

*

 

Jerry L. Peters (2) (9)

 

 

15,612

 

 

*

 

Scott A. Rogan (11)

 

 

 

 

*

 

Jeffrey R. Spinner (11)

 

 

 

 

*

 

Robert M. Wohleber (2)

 

 

27,310

 

 

*

 

James Lee Jacobe (2)

 

 

9,580

 

 

 

 

 

All directors and executive officers as a group (consisting of 15 persons)

 

 

1,012,533

 

 

*

 

 

* An asterisk indicates that the person or entity owns less than one percent.

(1)  Summit Investments owns 100% of SMP Holdings, the entity that owns 100% of our General Partner. Energy Capital Partners II, LLC ("ECP II") and its parallel and co-investment funds (the "ECP Funds" and together with ECP II, "ECP") hold in the aggregate, 100% of the Class A membership interests in Summit Investments, the sole owner of SMP Holdings. ECP II is the General Partner of the General Partner of each of the ECP Funds that holds membership interests in Summit Investments and has voting and investment control over the securities held thereby. Accordingly, ECP may be deemed to indirectly beneficially own all of the common units held by Summit Investments and SMP Holdings as of February 18, 2020.

(2)  The address for this person or entity is 910 Louisiana Street, Suite 4200, Houston, TX.

(3)  Because of its ownership interest in Summit Investments, ECP is entitled to elect five directors of Summit Investments. In addition, Mr. Delaney (who is a principal of Energy Capital Partners), Mr. Labbat (who is a partner of Energy Capital Partners), Mr. Lane (who is Vice Chairman of Energy Capital Partners), Mr. Rogan (who is a principal of Energy Capital Partners) and Mr. Spinner (who is a principal of Energy Capital Partners) are each directors of our General Partner. Neither Mr. Delaney, Mr. Labbat, Mr. Lane, Mr. Rogan nor Mr. Spinner are deemed to beneficially own, and they disclaim beneficial ownership of, any common units held by our General Partner, Summit Investments or SMP Holdings.

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(4)  SMP Holdings owns 100% of our General Partner and 48.4% of our outstanding common units. Given its ownership interest in Summit Investments, ECP may be deemed to indirectly beneficially own all of the common units held by SMP Holdings as of February 18, 2020.

(5)  The address for this person or entity is 51 John F. Kennedy Parkway, Suite 1250, Short Hills, NJ 07078.

(6)  Energy Capital Partners II, LP and certain of its parallel funds (collectively, the "SMLP Holdings Owners") collectively hold all of the membership interests in SMLP Holdings, LLC ("SMLP Holdings"). ECP II indirectly controls the SMLP Holdings Owners.  Accordingly, ECP II and the SMLP Holdings Owners may be deemed to indirectly beneficially own all of the common units held by SMLP Holdings.

(7)  The address for this person or entity is 1555 Peachtree Street NE, Suite 1800, Atlanta, GA 30309.

(8)  Includes common units which the individuals have the right to acquire upon vesting of phantom units, where the units are issuable as of February 18, 2020 or within 60 days thereafter. Such units are deemed to be outstanding in calculating the percentage ownership of such individual (and all directors and officers as a group), but are not deemed to be outstanding as to any other person.

(9)  Excludes vested units for which receipt has been deferred into our Deferred Compensation Plan.

(10)  Includes 20,000 common units held by Lane Ventures LLC ("Lane Ventures"). Two of Mr. Lane's estate planning trusts collectively own a majority of the membership interests in Lane Ventures and as a result, Mr. Lane may be deemed to indirectly beneficially own the common units held by Lane Ventures.

(11)  The address for this person or entity is 1000 Louisiana, Suite 5200, Houston, Texas 77002.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2019 with respect to the Partnership's common units that may be issued under the 2012 Long-Term Incentive Plan.

Plan category

 

Number of securities to be issued upon exercise of outstanding options, warrants and rights (a) (1)

 

 

Weighted-average exercise price of outstanding options, warrants and rights (b)

 

 

Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)

 

Equity compensation plans approved by security holders

 

 

2,105,995

 

 

n/a

 

 

 

1,277,309

 

Equity compensation plans not approved by security holders

 

n/a

 

 

n/a

 

 

n/a

 

Total

 

 

2,105,995

 

 

 

 

 

 

1,277,309

 

 

(1) Amount shown represents phantom unit awards outstanding under the SMLP LTIP at December 31, 2019. The awards are expected to be settled in common units upon the applicable vesting date and are not subject to an exercise price.

2012 SMLP Long-Term Incentive Plan.  In connection with the IPO, our General Partner approved the SMLP LTIP, pursuant to which eligible officers, employees, consultants and directors of our General Partner and its affiliates are eligible to receive awards with respect to our equity interests. The SMLP LTIP is designed to promote our interests, as well as the interests of our unitholders, by rewarding eligible officers, employees, consultants and directors for delivering desired performance results, as well as by strengthening our ability to attract, retain and motivate qualified individuals to serve as directors, consultants and employees. A total of 5,000,000 common units was reserved for issuance, pursuant to and in accordance with the SMLP LTIP.

The SMLP LTIP is administered by the Board of Directors. The SMLP LTIP provides for the grant, from time to time at the discretion of the Board of Directors, of unit awards, restricted units, phantom units, unit options, unit appreciation rights, distribution equivalent rights, profits interest units and other unit-based awards. Units that are canceled or forfeited are available for delivery pursuant to other awards.

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Common units to be delivered with respect to awards may be newly issued units, common units acquired by us or our General Partner in the open market, common units already owned by our General Partner or us, common units acquired by our General Partner directly from us or any other person or any combination of the foregoing.

The General Partner's Board of Directors, at its discretion, may terminate the SMLP LTIP at any time with respect to the common units for which a grant has not previously been made. The SMLP LTIP will automatically terminate on the 10th anniversary of the date it was initially adopted by our General Partner. The General Partner's Board of Directors also has the right to alter or amend the SMLP LTIP or any part of it from time to time or to amend any outstanding award made under the SMLP LTIP, provided that no change in any outstanding award may be made that would materially impair the rights of the participant without the consent of the affected participant.

Of the 93,493,473 common units outstanding at December 31, 2019, Summit Investments beneficially owned 45,318,866 common units and a subsidiary of Energy Capital Partners directly owned 5,915,827 common units. In addition, SMP Holdings owns and controls our General Partner.

Distributions and Payments to our General Partner and its Affiliates

The following summarizes the distributions and payments to be made by us to our General Partner and its affiliates in connection with our ongoing operations and our liquidation. These distributions and payments were determined by and among affiliated entities and, consequently, are not the result of arm's-length negotiations.

Operational Stage

Payments to our General Partner and its affiliates. See "Agreements with Affiliates—Reimbursement of Expenses from General Partner" below.

Liquidation Stage

Upon our liquidation, our partners, including our General Partner, will be entitled to receive liquidating distributions according to their particular capital account balances.

Agreements with Affiliates

We have various agreements with certain of our affiliates, as described below. These agreements have been negotiated among affiliated parties and, consequently, are not the result of arm's-length negotiations.

Reimbursement of Expenses from General Partner.  Under our Partnership Agreement, we reimburse our General Partner and its affiliates for certain expenses incurred on our behalf, including, without limitation, salary, bonus, incentive compensation and other amounts paid to our General Partner's employees and executive officers who perform services necessary to run our business. Our Partnership Agreement provides that our General Partner will determine in good faith the expenses that are allocable to us. Operation and maintenance expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were $28.6 million in 2019. General and administrative expenses incurred by the General Partner and reimbursed by us under our Partnership Agreement were $32.2 million in 2019. As of December 31, 2019, we had a payable of $0.3 million to the General Partner for expenses that were paid on our behalf.

Expense Allocations.  Certain of Summit Investments’ current and former employees received Class B membership interests, classified as net profits interests, in Summit Investments (the “Net Profits Interests”). The Net Profits Interests participate in distributions upon time vesting and the achievement of certain distribution targets to Class A members or higher priority vested Net Profits Interests. The Net Profits Interests were accounted for as compensatory awards.

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Review, Approval and Ratification of Related-Person Transactions

The Board of Directors has a policy for the identification, review and approval of certain related person transactions. The policy provides for the review and (as appropriate) approval by the Conflicts Committee of transactions between SMLP and its subsidiaries, on the one hand, and related persons (as that term is defined in SEC rules), on the other hand. Pursuant to the policy, the General Counsel of SMLP's General Partner is charged with primary responsibility for determining whether, based on the facts and circumstances, a proposed transaction is a related person transaction.

For purposes of the policy, a "related person" is any director or executive officer of SMLP's General Partner, any nominee for director, any unitholder known to SMLP to be the beneficial owner of more than 5% of any class of the SMLP's common units, and any immediate family member, affiliate or controlled subsidiary of any such person. A "related person transaction" is generally a transaction in which SMLP is, or SMLP's General Partner or any of SMLP's subsidiaries is, a participant, where the amount involved exceeds $120,000, and a related person has a direct or indirect material interest. Transactions resolved under the conflicts provision of the Partnership Agreement are not required to be reviewed or approved under the policy.

If, after weighing all of the facts and circumstances, the general counsel of SMLP's General Partner determines that a proposed transaction is a related person transaction that requires review or approval and the transaction meets certain monetary thresholds or involves certain related persons, management must present the proposed transaction to the Conflicts Committee for advance approval. If the transaction does not meet the designated monetary threshold or involve certain related persons, management presents the transaction(s) to the Committee for their review on a quarterly basis.

The policy described above was adopted by the Board of Directors on March 7, 2013, and as a result, certain of the transactions described in "Agreements with Affiliates" above were not reviewed under such policy.

Director Independence

Although most companies listed on the New York Stock Exchange are required to have a majority of independent directors serving on the board of directors of the listed company, the New York Stock Exchange does not require a listed limited partnership like us to have, and we do not intend to have, a majority of independent directors on the Board of Directors.

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Item 14. Principal Accounting Fees and Services.

Our Audit Committee has ratified Deloitte & Touche LLP, Independent Registered Public Accounting Firm, to audit the books, records and accounts of SMLP for the year ended December 31, 2019.

Audit Fees.  The fees billed by Deloitte & Touche LLP, as principal accountant, for the audit of our consolidated financial statements and other services rendered for the years ended December 31, 2019 and 2018 follow.

 

 

 

Year ended December 31,

 

 

 

2019

 

 

2018

 

Audit fees (1)

 

$

1,654,404

 

 

$

1,747,000

 

Audit-related fees (2)

 

 

20,000

 

 

 

75,500

 

Tax fees (3)

 

 

469,276

 

 

 

473,130

 

All other fees

 

 

 

 

 

 

Total

 

$

2,143,680

 

 

$

2,295,630

 

 

(1) Audit fees are fees billed by Deloitte & Touche LLP for professional services for the audit and quarterly reviews of the Partnership’s consolidated financial statements, review of other SEC filings, including registration statements, and issuance of comfort letters and consents.

(2) Represents fees related to our At-the-market Program (see Note 12 to the consolidated financial statements).

(3) Tax fees are billed by Deloitte Tax LLP for tax compliance services, including the preparation of state, federal and Schedule K-1 tax filings and other tax planning and advisory services.

Pre-approval Policy.  Pursuant to its charter, the Audit Committee is responsible for the appointment, compensation, retention and oversight of SMLP's independent auditor (including resolution of disagreements between management and the independent auditor regarding financial reporting). The Audit Committee shall have sole authority to pre-approve all audit, audit-related and permitted non-audit engagements with the independent auditor, including the fees and other terms of such engagements. The independent auditor shall report directly to the Audit Committee. The Audit Committee may consult with management but may not delegate these responsibilities to management.

 

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PART IV

 

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) Financial Statements

Included in Part II, Item 8, of this report:

Summit Midstream Partners, LP and Subsidiaries:

 

Report of Independent Registered Public Accounting Firm

109

Consolidated Balance Sheets as of December 31, 2019 and 2018

110

Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017

111

Consolidated Statements of Partners' Capital for the years ended December 31, 2019, 2018 and 2017

112

Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017

113

Notes to Consolidated Financial Statements

115

 

(2) Financial Statement Schedules

All schedules are omitted because the required information is inapplicable or the information is presented in the financial statements or the notes thereto.

SEC Rule 3-09 of Regulation S-X ("Rule 3-09") requires that we include or incorporate by reference financial statements for OGC in this Form 10-K if our investment was considered to be significant for the year ended December 31, 2019. We have concluded that OGC is significant. As such, the following documents are incorporated herein by reference:

 

The audited balance sheets of OGC as of December 31, 2019 and 2018 and the related statements of operations, members' equity and cash flows for the years ended December 31, 2019, 2018 and 2017 and the related notes to the financial statements, are filed as Exhibit 99.1 to this Report.

(3) Exhibit Index

An “Exhibit Index” has been filed as part of this Report included below and is incorporated herein by this reference.

Schedules other than those listed above are omitted because they are not required, are not material, are not applicable, or the required information is shown in the financial statements or notes thereto.

In reviewing the agreements included as exhibits to this annual report, please remember they are included to provide information regarding their terms and are not intended to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the other parties to the applicable agreement and:

 

should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

 

have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

 

may apply standards of materiality in a way that is different from what may be viewed as material by others; and

 

were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

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Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

(b) Exhibit Index

 

Exhibit

number

 

Description

3.1

 

Third Amended and Restated Agreement of Limited Partnership of Summit Midstream Partners, LP, dated as of March 22, 2019 (Incorporated herein by reference to Exhibit 3.1 to SMLP's Current Report on Form 8-K dated March 22, 2019 (Commission File No. 001-35666))

3.2

 

Amended and Restated Limited Liability Company Agreement of Summit Midstream GP, LLC, dated as of October 3, 2012 (Incorporated herein by reference to Exhibit 3.2 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))

3.3

 

Certificate of Limited Partnership of Summit Midstream Partners, LP (Incorporated herein by reference to Exhibit 3.1 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))

3.4

 

Certificate of Formation of Summit Midstream GP, LLC (Incorporated herein by reference to Exhibit 3.4 to SMLP's Form S-1 Registration Statement dated August 21, 2012 (Commission File No. 333-183466))

4.1

***

Description of Common Units

4.2

 

Investor Rights Agreement, dated as of October 3, 2012, by and among EFS-S, LLC, Summit Midstream GP, LLC and Summit Midstream Partners, LLC (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated October 4, 2012 (Commission File No. 001-35666))

10.2

 

Purchase Agreement, dated as of June 12, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., Summit Midstream GP, LLC, the Guarantors named therein and the Initial Purchasers named therein (Incorporated herein by reference to Exhibit 1.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))

10.3

 

Purchase and Sale Agreement between Meadowlark Midstream Company, LLC, Tioga Midstream, LLC and Hess North Dakota Pipelines LLC dated as of February 22, 2019 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666))

10.4

 

Purchase and Sale Agreement between Meadowlark Midstream Company, LLC, Tioga Midstream, LLC and Hess Infrastructure Partners LP dated as of February 22, 2019 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666))

10.5

 

Indenture, dated as of June 17, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 7½% senior notes due 2021) (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))

10.6

 

Registration Rights Agreement, dated as of June 17, 2013, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated June 17, 2013 (Commission File No. 001-35666))

10.7

 

Joinder Agreement, dated as of June 4, 2013, by and among Summit Midstream Holdings, LLC, The Royal Bank of Scotland plc, as Administrative Agent, and the lenders party thereto (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated June 5, 2013 (Commission File No. 001-35666))

10.8

 

Third Amended and Restated Credit Agreement dated as of May 26, 2017 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated May 30, 2017 (Commission File No. 001-35666))

10.9

 

First Amendment to the Third Amended and Restated Credit Agreement dated as of September 22, 2017

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10.10

 

Second Amendment to Third Amended and Restated Credit Agreement dated as of June 26, 2019 (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 10-Q dated August 9, 2019 (Commission File No. 001-35666))

10.11

***

Third Amendment to Third Amended and Restated Credit Agreement and Second Amendment to Second Amended and Restated Guarantee and Collateral Agreement dated as of December 24, 2019

10.12

***

Amended and Restated Limited Liability Company Agreement of Summit Permian Transmission Holdco, LLC, dated as of December 24, 2019

10.13

 

Amended and Restated Guarantee and Collateral Agreement dated as of November 1, 2013 (Incorporated herein by reference to Exhibit 10.7 to SMLP's 2013 Annual Report on Form 10-K for the fiscal year ended December 31, 2013 (Commission File No. 001-35666))

10.14

 

Base Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp. and U.S. Bank National Association (Incorporated herein by reference to Exhibit 4.1 to SMLP's Current Report on Form 8-K dated July 9, 2014 (Commission File No. 001-35666))

10.15

 

First Supplemental Indenture, dated as of July 15, 2014, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 5½% senior notes due 2022) (Incorporated herein by reference to Exhibit 4.2 to SMLP's Current Report on Form 8-K dated July 9, 2014 (Commission File No. 001-35666))

10.16

 

Second Supplemental Indenture, dated as of February 15, 2017, by and among Summit Midstream Holdings, LLC, Summit Midstream Finance Corp., the Guarantors party thereto and U.S. Bank National Association (including form of the 5.75% senior notes due 2025) (Incorporated herein by reference to Exhibit 4.2 to SMLP’s Current Report on Form 8-K dated February 17, 2017 (Commission File No. 001-35666))

10.17

 

Equity Distribution Agreement, dated June 12, 2015, among the Partnership, the General Partner, the Operating Company, Citigroup Global Markets Inc., Deutsche Bank Securities Inc. and RBC Capital Markets, LLC. (Incorporated herein by reference to Exhibit 1.1 to SMLP's Current Report on Form 8-K dated June 12, 2015 (Commission File No. 001-35666))

10.18

 

Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated as of February 25, 2016 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed March 1, 2016 (Commission File No. 001-35666))

10.19

 

Amendment to Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated February 25, 2019 (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666))

10.20

 

Amendment No. 2 to Contribution Agreement between Summit Midstream Partners Holdings, LLC and Summit Midstream Partners, LP dated November 7, 2019 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K dated November 8, 2019 (Commission File No. 001-35666))

10.21

 

Equity Restructuring Agreement by and among Summit Midstream Partners, LP, Summit Midstream GP, LLC and Summit Midstream Partners Holdings, LLC dated as of February 25, 2019 (Incorporated herein by reference to Exhibit 10.4 to SMLP's Current Report on Form 8-K dated February 26, 2019 (Commission File No. 001-35666))

10.22

*

Amendment No. 1 to Employment Agreement, dated December 1, 2015, effective August 4, 2017, by and between Summit Midstream Partners, LLC and Leonard Mallett (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K dated August 8, 2017 (Commission File No. 001-35666))

10.23

*

Second Amended and Restated Employment Agreement, effective March 1, 2017, by and between Summit Midstream Partners, LLC and Brad N. Graves (Incorporated herein by reference to Exhibit 10.24 to SMLP’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 (Commission File No. 001-35666))

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10.24

*

Amendment No. 1 to Amended and Restated Employment Agreement by and between Summit Midstream Partners LLC and Brock M. Degeyter, effective January 23, 2018 (Incorporated herein by reference to Exhibit 10.1 to SMLP's Form 8-K filed February 24, 2016 (Commission File No. 001-35666))

10.25

*

Employment Agreement, effective January 1, 2019, by and between Summit Midstream Partners, LLC and Marc D. Stratton (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Form 8-K dated January 2, 2019 (Commission File No. 001-35666))

10.26

*

Employment Agreement effective March 1, 2019, by and between Summit Midstream Partners, LLC and Louise E. Matthews (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated February 6, 2019 (Commission File Number 001-35666))

10.27

*

Form of Retention Bonus Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated June 11, 2019 (Commission File Number 001-35666))

10.28

*

Employment Agreement effective September 16, 2019, by and between Summit Midstream Partners, LLC and Heath Deneke (Incorporated herein by reference to Exhibit 10.1 to SMLP’s Current Report on Form 8-K dated August 9, 2019 (Commission File Number 001-35666))

10.29

*

Summit Midstream Partners, LP 2012 Long-Term Incentive Plan (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K filed October 4, 2012 (Commission File No. 001-35666))

10.30

*

Award Agreement by and between Summit Midstream GP, LLC, Summit Midstream Partners, LP and Leonard Mallett (Incorporated herein by reference to Exhibit 10.2 to SMLP's Current Report on Form 8-K filed November 17, 2015 (Commission File No. 001-35666))

10.31

*

Summit Midstream Partners, LP 2012 Long-Term Incentive Plan Phantom Unit Agreement (Incorporated herein by reference to Exhibit 10.1 to SMLP's Current Report on Form 8-K filed March 17, 2014 (Commission File No. 001-35666))

10.32

*

Form of Director Unit Award Agreement (Incorporated herein by reference to Exhibit 10.3 to SMLP's Current Report on Form 8-K filed October 4, 2012 (Commission File No. 001-35666))

10.33

*

Summit Midstream Partners, LLC Deferred Compensation Plan effective as of July 1, 2013 (Incorporated herein by reference to Exhibit 4.3 to SMLP's Form S-8 Registration Statement dated June 28, 2013 (File No. 333-189684))

21.1

 

List of Subsidiaries

23.1

 

Consent of Deloitte & Touche LLP - Summit Midstream Partners, LP

23.2

 

Consent of PricewaterhouseCoopers LLP - Ohio Gathering Company, L.L.C.

31.1

 

Rule 13a-14(a)/15d-14(a) Certification, executed by Heath Deneke, President, Chief Executive Officer and Director

31.2

 

Rule 13a-14(a)/15d-14(a) Certification, executed by Marc D. Stratton, Executive Vice President and Chief Financial Officer

32.1

 

Certifications required by Rule 13a-14(b) or Rule 15d-14(b) and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350), executed by Heath Deneke, President, Chief Executive Officer and Director, and Marc D. Stratton, Executive Vice President and Chief Financial Officer

99.1

***

Ohio Gathering Company, L.L.C. Financial Statements as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017

101.INS

**

XBRL Instance Document – the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

**

Inline XBRL Taxonomy Extension Schema

101.CAL

**

Inline XBRL Taxonomy Extension Calculation Linkbase

101.DEF

**

Inline XBRL Taxonomy Extension Definition Linkbase

101.LAB

**

Inline XBRL Taxonomy Extension Label Linkbase

101.PRE

**

Inline XBRL Taxonomy Extension Presentation Linkbase

104

 

Cover Page Interactive Data File (embedded within the Inline XBRL document).

 

* Management contract or compensatory plan or arrangement required to be filed as an exhibit pursuant to Item 15(b) of this report

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† Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been filed separately with the SEC.

** 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.

*** Filed herewith

(c) Financial Statement Schedules

Not applicable.

Item 16. Form 10-K Summary.

Not applicable.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

Summit Midstream Partners, LP

 

(Registrant)

 

 

 

By:  Summit Midstream GP, LLC (its General Partner)

 

 

March 9, 2020

/s/ Marc D. Stratton

 

Marc D. Stratton, Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

 

Title

 

Date

/s/ Heath Deneke

 

Director, President and Chief Executive Officer (Principal Executive Officer)

 

March 9, 2020

Heath Deneke

 

 

 

 

 

 

 

 

 

/s/ Marc D. Stratton

 

Executive Vice President and Chief Financial Officer (Principal Financial and Accounting Officer)

 

March 9, 2020

Marc D. Stratton

 

 

 

 

 

 

 

 

 

/s/ Matthew F. Delaney

 

Director

 

March 9, 2020

Matthew F. Delaney

 

 

 

 

 

 

 

 

 

/s/ Lee Jacobe

 

Director

 

March 9, 2020

Lee Jacobe

 

 

 

 

 

 

 

 

 

/s/ Peter Labbat

 

Director

 

March 9, 2020

Peter Labbat

 

 

 

 

 

 

 

 

 

/s/ Thomas K. Lane

 

Director

 

March 9, 2020

Thomas K. Lane

 

 

 

 

 

 

 

 

 

/s/ Jerry L. Peters

 

Director

 

March 9, 2020

Jerry L. Peters

 

 

 

 

 

 

 

 

 

/s/ Scott A. Rogan

 

Director

 

March 9, 2020

Scott A. Rogan

 

 

 

 

 

 

 

 

 

/s/ Jeffrey R. Spinner

 

Director

 

March 9, 2020

Jeffrey R. Spinner

 

 

 

 

 

 

 

 

 

/s/ Robert M. Wohleber

 

Director

 

March 9, 2020

Robert M. Wohleber

 

 

 

 

 

201