Item 1. Business
The consolidated financial statements of EQM have been retrospectively recast to include the pre-acquisition results of AVC, Rager Mountain Storage Company LLC (Rager) and certain gathering assets located in southwestern Pennsylvania and northern West Virginia (the Gathering Assets), which were acquired by EQM effective on October 1, 2016, (collectively, the October 2016 Acquisition), EQM Olympus Midstream LLC (formerly known as Rice Olympus Midstream LLC) (EQM Olympus), Strike Force Midstream Holdings LLC (Strike Force) and EQM West Virginia Midstream LLC (formerly known as Rice West Virginia Midstream LLC) (EQM WV), which were acquired by EQM effective on May 1, 2018 (the Drop-Down Transaction), and RM Partners LP (formerly known as Rice Midstream Partners LP) (RMP), which was acquired by EQM effective on July 23, 2018 (the EQM-RMP Merger), because these transactions were between entities under common control. All references in this Annual Report on Form 10-K to "EQM" refer to EQM in its individual capacity or to EQM and its consolidated subsidiaries, as the context requires. All references in this Annual Report on Form 10-K to "Equitrans Midstream" refer to Equitrans Midstream Corporation in its individual capacity or to Equitrans Midstream and its consolidated subsidiaries, as the context requires.
Overview of Operations
EQM Midstream Partners, LP (formerly known as EQT Midstream Partners, LP) (NYSE: EQM) is a growth-oriented limited partnership that operates, acquires and develops midstream assets in the Appalachian Basin. EQM is one of the largest natural
gas gatherers in the U.S. and holds a premier transmission footprint in the Appalachian Basin. EQM provides midstream services to its customers in Pennsylvania, West Virginia and Ohio through its three primary assets: the gathering system, which delivers natural gas from wells and other receipt points to transmission pipelines; the transmission and storage system, which delivers natural gas to local demand users and long-haul interstate pipelines for access to demand markets; and the water service system, which consists of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities that support well completion activities and collect flowback and produced water for recycling or disposal.
EQM provides a majority of its natural gas gathering, transmission and storage services under long-term, firm contracts that generally include fixed monthly reservation fees. This contract structure enhances the stability of EQM's cash flows and limits its direct exposure to commodity price risk. For the year ended
December 31, 2018
, approximately
54%
of EQM's revenues were generated from firm reservation fees under long-term contracts.
Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which EQM has executed firm contracts,
EQM's firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately
11
years and
15
years, respectively, as of
December 31, 2018
.
EQM's operations are focused primarily in southwestern Pennsylvania, northern West Virginia and southeastern Ohio, which are strategic locations in the natural gas shale plays known as the Marcellus, Utica and Upper Devonian Shales, respectively. These regions are also the primary operating area of EQT, EQM's largest customer. EQT accounted for approximately
74%
of EQM's revenues for the year ended
December 31, 2018
.
The following is a map of the EQM's gathering, transmission and storage and water services operations as of
December 31, 2018
.
2018 Highlights
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Average daily gathering throughput volumes increased
145.6%
from
2,642
Btu per day (BBtu/d) for the year ended
December 31, 2017
to
6,489
BBtu/d for the year ended
December 31, 2018
due largely to the acquisitions described below.
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EQM-RMP Merger
. On April 25, 2018, EQM, RMP and certain of their affiliates executed an agreement and plan of merger, pursuant to which EQM agreed to acquire RMP and the RMP General Partner. The EQM-RMP Merger closed on July 23, 2018. RMP's natural gas gathering system includes approximately 180 miles of natural gas gathering pipelines with gathering capacity of 5.1 TBtu/d and compression capacity of approximately 85,000 horsepower. In addition, RMP's water services assets consist of approximately 140 miles of water pipelines, impoundment facilities, pumping stations, take point facilities and measurement facilities in Washington and Greene Counties, Pennsylvania, and Belmont County, Ohio. See Note
2
to the consolidated financial statements for further information.
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The Gulfport Transaction
. On May 1, 2018, EQM acquired the remaining 25% of the outstanding limited liability company interests in Strike Force Midstream LLC (Strike Force Midstream) that it did not then own from Gulfport Midstream Holdings, LLC (Gulfport Midstream), an affiliate of Gulfport Energy Corporation, for $175 million in cash (the Gulfport Transaction). Strike Force Midstream is a Delaware limited liability company that owns and operates a natural gas gathering system consisting of approximately 67 miles of natural gas gathering pipelines and compressor stations.
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Drop-Down Transaction.
On May 22, 2018 and effective May 1, 2018, EQM, through its wholly owned subsidiary EQM Gathering Holdings, LLC (EQM Gathering), acquired from EQT all of the outstanding limited liability company interests in each of EQM Olympus, EQM WV and Strike Force pursuant to the terms of the Contribution and Sale Agreement (the Contribution Agreement). EQM Olympus' natural gas gathering system includes approximately 85 miles of natural gas gathering pipelines and compressor stations that transport gas from wells located primarily in Belmont County, Ohio. EQM WV assets include approximately 31 miles of right-of-way assets in northern West Virginia. See Note
2
to the consolidated financial statements for further information.
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Senior Notes Offering.
During the second quarter of 2018, EQM issued 4.75% senior notes due July 15, 2023 in the aggregate principal amount of $1.1 billion, 5.50% senior notes due July 15, 2028 in the aggregate principal amount of $850 million and 6.50% senior notes due July 15, 2048 in the aggregate principal amount of $550 million (collectively, the 2018 Senior Notes). The net proceeds were used to repay the balances outstanding under the EQM Term Loan Facility and the RMP $850 Million Facility, and the remainder was used for general partnership purposes. See Note
10
for further information.
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Amendment to EQM's credit facility
. On October 31, 2018, EQM amended and restated its $1 billion credit facility to increase the borrowing capacity under the credit facility from $1 billion to $3 billion and extend the maturity date to October 2023. See Note
10
for further information.
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The Separation.
On November 12, 2018, EQT effected the Separation of its upstream business, which is composed of the natural gas, oil and natural gas liquids development, production and sales and commercial operations of EQT (collectively, the Upstream Business) and its midstream business, which is composed of the separately-operated natural gas gathering, transmission and storage and water services of EQT (collectively, the Midstream Business). Following the Separation, Equitrans Midstream gained control of EQM and owns the Midstream Business previously held by EQT.
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EQM IDR Transaction
On February 13, 2019, Equitrans Midstream entered into a definitive agreement and plan of merger with the EQM General Partner (the IDR Merger Agreement) and certain related parties, pursuant to which, among other things, Equitrans Midstream will exchange and cancel the IDRs and economic general partner interest in EQM that it holds, indirectly, for (a) 80 million newly-issued EQM common units and 7 million newly-issued Class B units (Class B units), both representing limited partner interests in EQM, and (b) the retention of a non-economic general partner interest in EQM (the EQM IDR Transaction). As a result of the EQM IDR Transaction, (i) EQGP Services, LLC will replace EQM Midstream Services, LLC as the general partner of EQM and (ii) the IDRs and economic general partner interest in EQM will be exchanged and canceled.
The Class B units will become convertible at the holder’s option in three tranches, with 2.5 million becoming convertible on April 1, 2021, 2.5 million becoming convertible on April 1, 2022, and 2 million becoming convertible on April 1, 2023 (each, a Class B unit conversion date). Until the applicable Class B unit conversion date, the Class B units will not be entitled to receive any distributions of available cash. After the applicable Class B unit conversion date, whether or not such Class B units have
been converted into EQM common units, the Class B units will participate pro rata with the EQM common units in distributions of available cash. Furthermore, the Class B units will become convertible at the holder’s option into EQM common units immediately before a change of control of EQM.
The holders of Class B Units will vote together with the holders of EQM’s common units as a single class, except that Class B Units owned by the general partner of EQM and its affiliates will be excluded from voting if EQM common units owned by such parties are excluded from voting. Holders of Class B Units will be entitled to vote as a separate class on any matter that adversely affects the rights or preferences of the Class B Units in relation to other classes of partnership interests in any material respect or as required by law.
The completion of the EQM IDR Transaction is subject to certain conditions, including, among other things: (1) all required filings, consents, approvals, permits and authorizations of any governmental authority in connection with the EQM IDR Transaction having been made or obtained; (2) there being no law or injunction prohibiting the consummation of the EQM IDR Transaction; (3) subject to specified materiality standards, the accuracy of the representations and warranties of the other party; (4) compliance by the other party in all material respects with its covenants; and (5) the receipt by EQM and EQGP of certain opinions covering matters described in the partnership agreements of EQM and EQGP and in the IDR Merger Agreement with respect to the EQM IDR Transaction. The EQM IDR Transaction will be accomplished by merging a subsidiary of EQM with and into EQGP, with EQGP surviving as a wholly-owned subsidiary of EQM. EQM expects the EQM IDR Transaction to close in February 2019.
After giving effect to the EQM IDR Transaction, Equitrans Gathering Holdings, LLC (Equitrans Gathering Holdings), EQM GP Corporation (EQM GP Corp) and Equitrans Midstream Holdings, LLC (EMH), each a subsidiary of Equitrans Midstream, will hold
89,505,616
,
89,536
and
27,650,303
of EQM’s common units, respectively, representing an aggregate
56.5%
limited partner interest in EQM. Additionally, Equitrans Gathering Holdings, EQM GP Corp and EMH will hold
6,153,907
,
6,155
and
839,938
of Class B units, respectively, representing an aggregate
3.4%
limited partner interest in EQM. In total, Equitrans Midstream expects to own, directly or indirectly, a
59.9%
limited partner interest in EQM that consists of
117,245,455
EQM common units and
7,000,000
Class B units.
Business Segments
EQM conducts its business through three business segments: Gathering, Transmission and Water. These segments include all of EQM's operations. For discussion of the composition of the three segments, see Notes
1
and
5
to the consolidated financial statements included in "Item 8. Financial Statements and Supplementary Data."
The three business segments correspond to EQM's three primary assets: the gathering system, transmission and storage system and water system.
The following table summarizes the composition of EQM's operating revenue by business segment.
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Years Ended December 31,
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2018
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2017
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2016
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Gathering operating revenues
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67
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%
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57
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%
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54
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%
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Transmission operating revenues
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26
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%
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42
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%
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46
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%
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Water operating revenues
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7
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%
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1
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%
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—
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%
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EQM's Assets
Gathering assets
. As of
December 31, 2018
, EQM's gathering system included approximately
700
miles of high-pressure gathering lines with compression of approximately
333,000
horsepower and multiple interconnect points with EQM's transmission and storage system and to other interstate pipelines. EQM's gathering system also included approximately
1,500
miles of FERC-regulated, low-pressure gathering lines.
Transmission and Storage assets
. As of
December 31, 2018
, EQM's transmission and storage system included approximately
950
miles of FERC-regulated, interstate pipeline that have interconnect points to
seven
interstate pipelines and LDCs. The transmission and storage system is supported by
41
compressor units, with total throughput capacity of approximately
4.4
Bcf per day and compression of approximately
120,000
horsepower, and
18
associated natural gas storage reservoirs, which have a peak withdrawal capacity of approximately
645
MMcf
per day and a working gas capacity of approximately
43
Bcf
.
Water assets
. As of
December 31, 2018
, EQM's water system included
two
independent systems composed of approximately
160
miles of pipeline that deliver fresh water from the Monongahela River, the Ohio River, local reservoirs and several regional waterways. In addition, as of December 31, 2018, the water system assets included
28
fresh water impoundment facilities.
Strategy
EQM’s assets overlay core acreage in the prolific Appalachian Basin. The location of EQM’s assets allows it to access major demand markets in the U.S. EQM is one of the largest natural gas gatherers in the U.S., and its largest customer, EQT, is the largest natural gas producer in the U.S. based on produced volumes. EQM maintains a stable cash flow profile, with over 50% of its revenue for the year ended December 31, 2018 generated by firm reservation fees.
EQM’s principal strategy is to leverage its existing and planned growth projects and to seek and execute on strategically-aligned acquisition and joint venture opportunities to achieve the scale and scope of a top-tier midstream company. As part of its approach to organic growth, EQM is focused on building and completing its key gathering and transmission growth projects outlined below, many of which are supported by contracts with firm capacity commitments. Additionally, EQM expects to achieve growth from its water service business and from volumetric gathering opportunities and transmission and storage services. The water service business is complementary to the gathering business, and EQM recognizes an opportunity to expand its existing asset footprint and is actively pursuing solutions for produced water handling. EQM is also focused on optimizing and integrating its Pennsylvania gathering systems to create additional system gathering capacity and provide high- and low-pressure gathering solutions for its customers. EQM’s focus on execution of its organic projects, coupled with asset optimization efforts, disciplined capital spending and operating cost control, is complemented by EQM’s commitment to seek, evaluate and execute on strategically-aligned acquisition and joint venture opportunities. EQM believes that this approach will enable EQM to achieve its strategic goals.
EQM expects that the following expansion projects will be its primary organic growth drivers:
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Mountain Valley Pipeline
. The MVP Joint Venture is a joint venture with EQM and affiliates of each of NextEra Energy, Inc., Con Edison, AltaGas Ltd. and RGC Resources, Inc. that is constructing the MVP. As of December 31, 2018, EQM is the operator of the MVP and owned a 45.5% interest in the MVP Joint Venture. The MVP is an estimated 300 mile, 42-inch diameter natural gas interstate pipeline with a targeted capacity of 2.0 Bcf per day that will span from EQM's existing transmission and storage system in Wetzel County, West Virginia to Pittsylvania County, Virginia, providing access to the growing southeast demand markets. As currently designed, the MVP is estimated to cost a total of approximately $4.6 billion, excluding AFUDC, of which EQM is expected to fund approximately $2.2 billion through capital contributions to the MVP Joint Venture, including approximately $65 million in excess of EQM's ownership interest. In 2019, EQM expects to make capital contributions of approximately $0.9 billion to the MVP Joint Venture, depending on the timing of the construction of the MVP and the MVP Southgate projects. The MVP Joint Venture has secured a total of 2.0 Bcf per day of firm capacity commitments at 20-year terms and is currently in negotiation with additional shippers that have expressed interest in the MVP project. The MVP Joint Venture is evaluating an expansion opportunity that could add approximately 0.5 Bcf per day of capacity through the installation of incremental compression. The MVP Joint Venture is also undertaking the MVP Southgate project and is evaluating other future pipeline extension projects.
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In October 2017, the FERC issued the Certificate of Public Convenience and Necessity for the MVP. In the first quarter of 2018, the MVP Joint Venture received limited notice to proceed with certain construction activities from the FERC and commenced construction. As discussed under "
The regulatory approval process for the construction of new midstream assets is challenging, and recent decisions by regulatory and judicial authorities in pending proceedings could impact EQM's or the MVP Joint Venture's ability to obtain all approvals and authorizations necessary to complete certain projects on the projected time frame or at all or EQM's ability to achieve the expected investment return on the project
" in "Item 1A. Risk Factors — Risks Inherent in Our Business," there are several pending challenges to certain aspects of the MVP project that must be resolved before the MVP project can be completed. The MVP Joint Venture is working to respond to the court and agency decisions and restore all permits. The MVP is targeted to be placed in service during the fourth quarter of 2019, subject to litigation and regulatory-related delay as further discussed in "Item 3. Legal Proceedings."
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Wellhead Gathering Expansion and Hammerhead Project.
In 2019, EQM expects to invest approximately $900 million in gathering expansion projects, including the continued gathering infrastructure expansion of core development areas in the Marcellus and Utica Shales, primarily in southwestern Pennsylvania and eastern Ohio, for EQT, Range Resources Corporation (Range Resources) and other producers, and the Hammerhead project, a 1.6 Bcf per day gathering header pipeline that is designed to connect natural gas produced in Pennsylvania and West Virginia to the MVP and is supported by a 1.2 Bcf per day firm capacity commitment from EQT. The Hammerhead project is expected to cost a total of approximately
$555 million
. EQM expects to invest approximately $400 million in the
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Hammerhead project in 2019. The Hammerhead project is expected to be placed in service in conjunction with the MVP project in the fourth quarter of 2019.
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MVP Southgate Project.
In April 2018, the MVP Joint Venture announced the MVP Southgate project, a proposed 70-mile interstate pipeline that will extend from the MVP at Pittsylvania County, Virginia to new delivery points in Rockingham and Alamance Counties, North Carolina. The MVP Southgate project is backed by a 300 MMcf per day firm capacity commitment from PSNC Energy. As designed, the MVP Southgate project has expansion capabilities that could provide up to 900 MMcf per day of total capacity. The MVP Southgate project is estimated to cost a total of approximately $450 million to $500 million, which is expected to be spent primarily in 2019 and 2020. In 2019, EQM expects to provide capital contributions of approximately $40 million to the MVP Joint Venture for the MVP Southgate project. In the fourth quarter of 2018, EQM assumed a portion of Con Edison's ownership interest and purchased a portion of PSNC Energy's ownership interest in the MVP Southgate project. As a result of these transactions, EQM's ownership interest increased from 32.7% to 47.2%. As of December 31, 2018, EQM was the operator of the MVP Southgate pipeline and owned a 47.2% interest in the MVP Southgate project. The MVP Joint Venture submitted the MVP Southgate certificate application to the FERC in November 2018. Subject to approval by the FERC, the MVP Southgate project has a targeted in-service date of the fourth quarter of 2020.
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Transmission Expansion
. In 2019, EQM expects to invest approximately $60 million in other transmission expansion projects, primarily attributable to the AVC, the Equitrans, L.P. Expansion project, which is designed to provide north-to-south capacity on the mainline Equitrans, L.P. system for deliveries to the MVP, and power plant projects. The Equitrans, L.P. Expansion project has a targeted in-service date of the fourth quarter of 2019.
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Transmission – New Power Plant Connection
. EQM recently executed a precedent agreement with ESC Brooke County Power I, LLC to construct a natural gas pipeline for connection to a proposed 830-Megawatt power plant in Brooke County, West Virginia. The agreement includes a ten-year firm reservation commitment for 140 MMcf per day of capacity. EQM expects to invest an estimated $80 million to construct the approximately 16-mile pipeline, which has a targeted in-service date of mid-year 2022.
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Water Expansion.
In 2019, EQM expects to invest approximately $100 million in the expansion of its fresh water delivery infrastructure in Pennsylvania and Ohio. EQM recently expanded its water service relationship with EQT and entered into agreements with four other Marcellus and Utica producers.
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Our Relationship with Equitrans Midstream
As a result of the Separation, Equitrans Midstream replaced EQT as our ultimate parent. Unlike EQT, Equitrans Midstream is a pure-play midstream company whose only cash-generating assets are its ownership interests in EQM.
Markets and Customers
EQM's two largest customers are EQT and its affiliates and PNG Companies LLC and its affiliates. EQT, the largest natural gas producer in the United States, accounted for approximately
74%
,
74%
and
75%
, respectively of EQM's total revenues for the
years ended December 31, 2018, 2017 and 2016
. For the
years ended December 31, 2018, 2017 and 2016
, PNG Companies LLC and its affiliates, an LDC, accounted for approximately
7%
,
11%
and
12%
, respectively, of EQM's total revenues, all of which was included in Transmission.
Gathering Customers.
For the year ended
December 31, 2018
, EQT accounted for approximately
80%
of Gathering's revenues. Subject to certain exceptions and limitations, Gathering has acreage dedications through which EQM has the right to elect to gather all natural gas produced from wells under an area covering (i) approximately
260,000
gross acres in Pennsylvania pursuant to agreements with certain affiliates of EQT and certain third parties, and (ii) approximately
176,000
gross acres in Ohio pursuant to agreements with certain affiliates of EQT and other third parties. In addition, Gathering has an acreage dedication of approximately
5,000
gross acres, with a producer option to expand towards approximately 30,000 gross acres, in Pennsylvania, pursuant to which EQM has the right to provide a proposal to gather all natural gas provided from wells under that area.
EQM provides gathering services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access. As of
December 31, 2018
, the gathering system had total contracted firm reservation capacity of approximately
2.4
Bcf per day. Including future capacity expected from expansion projects that are not yet fully constructed for which EQM has executed firm contracts, the gathering system had total contracted firm reservation capacity of approximately
2.7
Bcf per day as of
December 31, 2018
. Volumetric-based fees can also be charged under firm contracts for each firm volume gathered as well as for volumes gathered in excess of the firm contracted volume, if system capacity exists.
Based on total projected contractual
revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which EQM has executed firm contracts,
EQM's firm gathering contracts had a weighted average remaining term of approximately
11 years
as of
December 31, 2018
.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas gathered and generally do not guarantee access to the pipeline. These contracts can be short- or long-term. On EQM's low-pressure regulated gathering system, the typical gathering agreement provides interruptible service and has a one-year term with month-to-month rollover provisions terminable upon at least 30 days' notice. The rates for gathering service on the regulated system are based on the maximum posted tariff rate and assessed on actual receipts into the gathering system.
EQM generally does not take title to the natural gas gathered for its customers but retains a percentage of wellhead gas receipts to recover natural gas used to power its compressor stations and meet other requirements on EQM's low- and high-pressure gathering systems.
Transmission Customers.
For the year ended
December 31, 2018
, EQT accounted for approximately
62%
of Transmission's throughput and approximately
54%
of Transmission's revenues. Transmission has an acreage dedication from EQT through which EQM has the right to elect to transport all gas produced from wells drilled by EQT under an area covering approximately
60,000
acres in Allegheny, Washington and Greene Counties in Pennsylvania and Wetzel, Marion, Taylor, Tyler, Doddridge, Harrison and Lewis Counties in West Virginia. For the year ended
December 31, 2018
, PNG Companies, LLC and its affiliates accounted for approximately
27%
of Transmission's revenues. Other customers include LDCs, marketers, producers and commercial and industrial users. EQM's transmission and storage system provides customers with access to adjacent markets in Pennsylvania, West Virginia and Ohio and to the Mid-Atlantic, Northeastern, Midwestern and Gulf Coast markets through interconnect points with major interstate pipelines.
EQM provides transmission and storage services in two manners: firm service and interruptible service. Firm service contracts are typically long-term and can include firm reservation fees, which are fixed, monthly charges for the guaranteed reservation of pipeline access and storage capacity. Volumetric-based fees can also be charged under firm contracts for firm volume transported or stored as well as for volumes transported or stored in excess of the firm contracted volume, if there is system capacity. Customers are not assured capacity or service for volumes in excess of the firm contracted volume as such volumes have the same priority as interruptible service. Including future capacity expected from expansion projects that are not yet fully constructed for which EQM has executed firm transmission contracts, approximately
5.0
Bcf per day of transmission capacity and
29.3
Bcf of storage capacity were subscribed under firm transmission and firm storage contracts, respectively, as of
December 31, 2018
. Based on total projected contractual revenues, including projected contractual revenues from future capacity expected from expansion projects that are not yet fully constructed for which EQM has executed firm contracts, EQM's firm transmission and storage contracts had a weighted average remaining term of approximately
15
years as of
December 31, 2018
.
Interruptible service contracts include volumetric-based fees, which are charges for the volume of natural gas transported and generally do not guarantee access to the pipeline or storage facility. These contracts can be short- or long-term. Customers with interruptible service contracts are not assured capacity or service on the transmission and storage systems. To the extent that capacity reserved by customers with firm service contracts is not fully used or excess capacity exists, the transmission and storage systems can allocate capacity to interruptible services. EQM generally does not take title to the natural gas transported or stored for its customers.
As of
December 31, 2018
, approximately
86%
of Transmission's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Approximately
10%
of Transmission's contracted firm transmission capacity was subscribed at recourse rates under its tariff, which are the maximum rates an interstate pipeline may charge for its services under its tariff. The remaining
4%
of Transmission's contracted firm transmission capacity was subscribed at discounted rates under its tariff, which are less than the maximum rates an interstate pipeline may charge for its services under its tariff.
Water Customers
. For the year ended
December 31, 2018
, EQT accounted for approximately
93%
of Water's revenues. EQM has the exclusive right to provide fluid handling services to certain EQT operated wells until December 22, 2029 (and thereafter such right continues on a month-to-month basis) within areas of dedication in Washington and Greene Counties, Pennsylvania and Belmont County, Ohio, including the delivery of fresh water for well completion operations and the collection and recycling or disposal of flowback and produced water. EQM also provides water services to other customers operating in the Marcellus and Utica Shales. EQM's water service revenues are primarily generated under variable price per volume contracts. The fees charged by EQM are generally tiered and, thus, are lower on a per gallon basis once certain thresholds are met.
Competition
Key competitors for new natural gas gathering systems include companies that own major natural gas pipelines, independent gas gatherers and integrated energy companies. When compared to EQM or its customers, some of EQM's competitors have greater capital resources and access to, or control of, larger natural gas supplies.
Competition for natural gas transmission and storage is primarily based on rates, customer commitment levels, timing, performance, commercial terms, reliability, service levels, location, reputation and fuel efficiencies. EQM's principal competitors in its transmission and storage market include companies that own major natural gas pipelines in the Marcellus, Utica and Upper Devonian Shales. In addition, EQM competes with companies that are building high-pressure gathering facilities that are able to transport natural gas to interstate pipelines without being subject to FERC jurisdiction. Major natural gas transmission companies that compete with EQM also have storage facilities connected to their transmission systems that compete with certain of EQM's storage facilities.
Key competition for water services include natural gas producers that develop their own water distribution systems in lieu of employing EQM's water services assets and other natural gas midstream companies that offer water services. EQM's ability to attract customers to its water service business depends on its ability to evaluate and select suitable projects and to consummate transactions in a highly competitive environment.
Regulatory Environment
FERC Regulation.
EQM's interstate natural gas transmission and storage operations are regulated by the FERC under the NGA, the NGPA and the Energy Policy Act of 2005. EQM's regulated system operates under tariffs approved by the FERC that establish rates, cost recovery mechanisms and the terms and conditions of service to its customers. Generally, the FERC's authority extends to:
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rates and charges for natural gas transmission, storage and FERC-regulated gathering services;
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certification and construction of new interstate transmission and storage facilities;
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abandonment of interstate transmission and storage services and facilities;
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maintenance of accounts and records;
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relationships between pipelines and certain affiliates;
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terms and conditions of services and service contracts with customers;
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depreciation and amortization policies;
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acquisition and disposition of interstate transmission and storage facilities; and
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initiation and discontinuation of interstate transmission and storage services.
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EQM holds certificates of public convenience and necessity for its transmission and storage system issued by the FERC pursuant to Section 7 of the NGA covering rates, facilities, activities and services. These certificates require EQM to provide open-access services on its interstate pipeline and storage facilities on a not unduly discriminatory basis to all customers that qualify under the FERC gas tariffs. In addition, under Section 8 of the NGA, the FERC has the power to prescribe the accounting treatment of certain items for regulatory purposes. Thus, the books and records of EQM's interstate pipeline and storage facilities may be periodically audited by the FERC.
The FERC regulates the rates and charges for transmission and storage in interstate commerce. Under the NGA, recourse rates charged by interstate pipelines must be just and reasonable.
The recourse rate that EQM may charge for its services is established through the FERC's cost-of-service ratemaking process. Generally, the maximum filed recourse rates for interstate pipelines are based on the cost of providing that service including recovery of and a return on the pipeline's actual prudent historical cost of investment. Key determinants in the ratemaking process include the depreciated capital costs of the facilities, the costs of providing service, the allowed rate of return and income tax allowance, as well as volume throughput and contractual capacity commitment assumptions. On March 15, 2018, the FERC issued an order prohibiting MLP-owned pipelines from including an allowance for investor income tax liability in their cost-of-service based rates. Under its prior policy, the FERC had permitted all interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated recourse rates. On July 18, 2018, the FERC issued an order affirming the principal finding in the March order regarding income tax recovery and also clarifying the
treatment of Accumulated Deferred Income Taxes (ADIT) in light of the prohibition on MLP income tax allowances. Challenges to these orders are currently pending in a consolidated proceeding before the U.S. Court of Appeals for the District of Columbia Circuit. On October 17, 2018, an intervenor filed a motion to hold the proceeding in abeyance. On October 24, 2018, the FERC filed a motion to dismiss the proceeding. The court has not acted on either motion at this time. EQM cannot currently predict when the court will act on these motions. Also, on July 18, 2018, the FERC issued Order No. 849, adopting regulations requiring that natural gas pipelines submit a one-time report, Form 501-G, due in the fourth quarter of 2018. Rehearing of Order No. 849 has been requested and is currently pending before the FERC. For MLP-owned pipelines, the Form 501-G report calculates an earned rate of return on equity that attempts to identify potential cost of service of over-recovery arising from the Tax Cuts and Jobs Act, the FERC's prohibition of an income tax allowance for MLP-owned pipelines and the ADIT clarification. On December 28, 2018, Equitrans, L.P. filed its Form 501-G with the FERC. The FERC will evaluate these Form 501-G filings on a case-by-case basis and permit a limited or a general rate case initiated by pipelines, open an investigation, or take no further action. The FERC has initiated rate cases against at least four pipelines as a result of their respective Form 501-G filings. We cannot determine whether the FERC or any customer will initiate a rate case against Equitrans, L.P. as a result of its Form 501-G filing or for any other reason. The maximum applicable recourse rates and terms and conditions for service are set forth in the pipeline's FERC-approved tariff. Rate design and the allocation of costs also can affect a pipeline's profitability. While the ratemaking process establishes the maximum rate that can be charged, interstate pipelines such as EQM's transmission and storage system are permitted to discount their firm and interruptible rates without further FERC authorization down to a specified minimum level, provided they do not unduly discriminate. In addition, pipelines are allowed to negotiate different rates with their customers, as described later in this section.
Changes to rates or terms and conditions of service can be proposed by a pipeline company under Section 4 of the NGA, or the existing interstate transmission and storage rates or terms and conditions of service may be challenged by a complaint filed by interested persons including customers, state agencies or the FERC under Section 5 of the NGA. Rate increases proposed by a pipeline may be allowed to become effective subject to refund and/or a period of suspension, while rates or terms and conditions of service which are the subject of a complaint under Section 5 of the NGA are subject to prospective change by the FERC. Rate increases proposed by a regulated interstate pipeline may be challenged and such increases may ultimately be rejected by the FERC. Any successful challenge against existing or proposed rates charged for EQM's transmission and storage services could have a material adverse effect on its business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to its unitholders.
EQM's interstate pipeline may also use negotiated rates which could involve rates above or below the recourse rate or rates that are subject to a different rate structure than the rates specified in EQM's interstate pipeline tariffs, provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement. A prerequisite for allowing the negotiated rates is that negotiated rate customers must have had the option to take service under the pipeline's recourse rates. As of
December 31, 2018
, approximately
86%
of the system's contracted firm transmission capacity was subscribed by customers under negotiated rate agreements under its tariff. Some negotiated rate transactions are designed to fix the negotiated rate for the term of the firm transportation agreement and the fixed rate is generally not subject to adjustment for increased or decreased costs occurring during the contract term.
FERC regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the form of service agreements set forth in the pipeline's FERC-approved tariff. In the event that the FERC finds that an agreement, in whole or part, is materially non-conforming, it could reject the agreement, require EQM to seek modification of the agreement or require EQM to modify its applicable tariff so that the non-conforming provisions are generally available to all customers.
FERC Regulation of Gathering Rates and Terms of Service.
While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, it has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. EQM maintains rates and terms of service in its tariff for unbundled gathering services performed on its gathering facilities in connection with the transmission service. Just as with rates and terms of service for transmission and storage services, EQM's rates and terms of services for its FERC-regulated low pressure gathering system may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service EQM proposes for its FERC-regulated low pressure gathering service may be protested, and such increases or changes can be delayed and may ultimately be rejected by the FERC.
Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by the FERC under the NGA. EQM believes that its high-pressure gathering systems meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation in the industry, so the
classification and regulation of these systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
Pipeline Safety and Maintenance.
EQM's interstate natural gas pipeline system is subject to regulation by PHMSA. PHMSA has established safety requirements pertaining to the design, installation, testing, construction, operation and maintenance of gas pipeline facilities, including requirements that pipeline operators develop a written qualification program for individuals performing covered tasks on pipeline facilities and implement pipeline integrity management programs. These integrity management plans require more frequent inspections and other preventive measures to ensure safe operation of oil and natural gas transportation pipelines in HCAs, such as high population areas or facilities that are hard to evacuate and areas of daily concentrations of people.
Notwithstanding the investigatory and preventative maintenance costs incurred in EQM's performance of customary pipeline management activities, EQM may incur significant additional expenses if anomalous pipeline conditions are discovered or more stringent pipeline safety requirements are implemented. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines. The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Further, in June 2016, then-President Obama signed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (the 2016 Pipeline Safety Act), extending PHMSA's statutory mandate under prior legislation through 2019. In addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two separate Interim Final Rules that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule; however, no final rule has been issued. Additionally, in January 2017, PHMSA announced a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in HCAs, extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs, and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. EQM is monitoring and evaluating the effect of these and other emerging requirements on its operations.
States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of EQM's natural gas facilities fall within a class that is not subject to integrity management requirements, EQM may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with its non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down EQM's pipelines during the pendency of such actions, could be material.
Should EQM fail to comply with DOT regulations adopted under authority granted to PHMSA, it could be subject to penalties and fines. PHMSA has the statutory authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, EQM may be required to make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in its forecasted maintenance capital expenditures.
EQM believes that its operations are in substantial compliance with all existing federal, state and local pipeline safety laws and regulations. However, the adoption of new laws and regulations, such as those proposed by PHMSA, could result in significant added costs or delays in service or the termination of projects, which could have a material adverse effect on EQM in the future.
Environmental Matters
General
. EQM's operations are subject to stringent federal, state and local laws and regulations relating to the protection of the environment. These laws and regulations can restrict or affect EQM's business activities in many ways, such as:
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requiring the acquisition of various permits to conduct regulated activities;
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requiring the installation of pollution-control equipment or otherwise restricting the way EQM can handle or dispose of its wastes;
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limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species; and
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requiring investigatory and remedial actions to mitigate or eliminate pollution conditions caused by EQM's operations or attributable to former operations.
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In addition, EQM's operations and construction activities are subject to county and local ordinances that restrict the time, place or manner in which those activities may be conducted so as to reduce or mitigate nuisance-type conditions, such as, for example, excessive levels of dust or noise or increased traffic congestion.
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations and the issuance of orders enjoining future operations or imposing additional compliance requirements. Also, certain environmental statutes impose strict, and in some cases joint and several, liability for the cleanup and restoration of sites where hydrocarbons or wastes have been disposed or otherwise released regardless of the fault of the current site owner or operator. Consequently, EQM may be subject to environmental liability at its currently owned or operated facilities for conditions caused by others prior to its involvement.
EQM has implemented programs and policies designed to keep its pipelines and other facilities in compliance with existing environmental laws and regulations, and EQM does not believe that its compliance with such legal requirements will have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make quarterly cash distributions to its unitholders. Nonetheless, the trend in environmental regulation is to place 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 significantly in excess of the amounts EQM currently anticipates. For example, in October 2015, the EPA revised the NAAQS for ozone from 75 parts per billion for the current 8-hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate the areas in which EQM operates as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound and methane emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The EPA finalized amendments to some requirements in these standards in March 2018 and September 2018, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of EQM's equipment, result in longer permitting timelines, and significantly increase EQM's capital expenditures and operating costs, which could adversely affect EQM's business. EQM tries 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. While EQM believes that it is in substantial compliance with existing environmental laws and regulations, there is no assurance that the current conditions will continue in the future.
The following is a discussion of several of the material environmental laws and regulations, as amended from time to time, that relate to EQM's business.
Hazardous Substances and Waste.
CERCLA and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include current and prior owners or operators of the site where a release of hazardous substances occurred and companies that transported, disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these "responsible persons" may be subject to strict and joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third
parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. EQM generates materials in the course of its ordinary operations that are regulated as "hazardous substances" under CERCLA or similar state laws and, as a result, may be jointly and severally liable under CERCLA, or such laws, for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.
EQM also generates solid wastes, including hazardous wastes, which are subject to the requirements of RCRA, and comparable state statutes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. In the ordinary course of EQM's operations, EQM generates wastes constituting solid waste and, in some instances, hazardous wastes. While certain petroleum production wastes are excluded from RCRA's hazardous waste regulations, it is possible that these wastes will in the future be designated as "hazardous wastes" and be subject to more rigorous and costly disposal requirements, which could have a material adverse effect on EQM's maintenance capital expenditures and operating expenses.
EQM owns, leases or operates properties where petroleum hydrocarbons are being or have been handled for many years. EQM has generally utilized operating and disposal practices that were standard in the industry at the time, although petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned, leased or operated by EQM, or on or under the other locations where these petroleum hydrocarbons and wastes have been transported for treatment or disposal. In addition, certain of these properties have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons and other wastes were not under EQM's control. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, EQM 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.
Air Emissions.
The federal Clean Air Act and comparable state laws and regulations restrict the emission of air pollutants from various industrial sources, including EQM's compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that EQM obtain pre-approval for the construction or modification of certain projects or facilities, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. EQM's failure to comply with these requirements could subject it to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. EQM may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining permits and approvals for air emissions. Compliance with these requirements may require modifications to certain of EQM's operations, including the installation of new equipment to control emissions from EQM's compressors that could result in significant costs, including increased capital expenditures and operating costs, and could adversely affect EQM's business.
Climate Change.
Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs.
The U.S. Congress, along with federal and state agencies, has considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase EQM's cost of environmental compliance by requiring EQM to install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities or impose additional monitoring and reporting requirements. For example, in October 2015, the EPA expanded the petroleum and natural gas system sources for which annual GHG emissions reporting would be required. Additionally, several states are pursuing similar measures to regulate emissions of GHGs from new and existing sources. If implemented, such restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of GHGs that could have an adverse effect on EQM's operations. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit EQM by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels such as coal. The effect on EQM of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Water Discharges.
The federal Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants or dredged and fill material into state waters as well as waters of the United States, including adjacent wetlands. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of permits issued by the EPA, the U.S. Army Corps of Engineers (U.S. Army Corps) or an analogous state agency. In September 2015, new EPA
and U.S. Army Corps rules defining the scope of the EPA's and the U.S. Army Corps' jurisdiction became effective (the 2015 Clean Water Rule). But the 2015 Clean Water Rule was promptly challenged in courts and was enjoined by judicial action in some states. Further, it has been delayed in effectiveness through agency rulemaking until February 6, 2020 nationwide. In December 2018, the EPA and the U.S. Army Corps of Engineers issued a proposed rule narrowing the scope of the Clean Water Act's jurisdiction. To the extent that any future rules expand the scope of the Clean Water Act's jurisdiction, EQM could face increased costs and delays with respect to obtaining permits for activities in jurisdictional waters, including wetlands.
Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws. EQM believes that compliance with existing permits and foreseeable new permit requirements will not have a material adverse effect on its business, financial condition, results of operations, liquidity or ability to make quarterly cash distributions to its unitholders.
National Environmental Policy Act.
The construction of interstate natural gas transportation pipelines pursuant to the NGA requires authorization from the FERC. The FERC actions are subject to the National Environmental Policy Act (NEPA). NEPA requires federal agencies, such as the FERC, to evaluate major federal actions having the potential to significantly affect the environment. In the course of such evaluations, an agency will either prepare an environmental assessment that assesses the potential direct, indirect and cumulative effects of a proposed project or, if necessary, a more detailed Environmental Impact Statement. Any proposed plans for future construction activities that require FERC authorization will be subject to the requirements of NEPA. This process has the potential to significantly delay or limit, and increase the cost of, development of midstream infrastructure.
Endangered Species Act.
The federal Endangered Species Act (ESA) restricts activities that may adversely affect endangered and threatened species or their habitats. Federal agencies are required to ensure that any action authorized, funded or carried out by them is not likely to jeopardize the continued existence of listed species or modify their critical habitat. While some of EQM's facilities are located in areas that are designated as habitats for endangered or threatened species, EQM believes that it is in substantial compliance with the ESA. The designation of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, could cause EQM to incur additional costs, result in delays in construction of pipelines and facilities, or cause EQM to become subject to operating restrictions in areas where the species are known to exist. For example, the U.S. Fish and Wildlife Service continues to receive hundreds of petitions to consider listing additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which EQM operates.
Employee Health and Safety.
EQM is subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (OSHA) and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community "right-to-know" regulations and comparable state laws and regulations require that information be maintained concerning hazardous materials used or produced in EQM's operations and that this information be provided to employees, state and local government authorities and citizens. EQM believes that it is in substantial compliance with all applicable laws and regulations relating to worker health and safety.
Seasonality
Weather affects natural gas demand for power generation and heating purposes. Peak demand for natural gas typically occurs during the winter months as a result of the heating load.
Insurance
In the Predecessor period, EQM generally shared insurance coverage with EQT. Subsequent to the Separation, EQM generally shares insurance coverage with Equitrans Midstream. EQM reimburses Equitrans Midstream for the cost of the insurance pursuant to the terms of the ETRN Omnibus Agreement. The insurance program includes excess liability insurance, auto liability insurance, workers' compensation insurance and property insurance. In addition, EQM has procured separate general liability and directors and officers liability policies. All insurance coverage is in amounts management believes to be reasonable and appropriate.
Employees
EQM does not have any employees. EQM is managed by the directors and officers of EQM Midstream Services, LLC, the general partner of EQM (EQM General Partner). Following the completion of the EQM IDR Transaction, EQM will be managed by the same directors and officers, except that those directors and officers will be directors and officers of EQGP Services, LLC, the then general partner of EQM (Post-IDR Transaction EQM General Partner). All executive management personnel of the EQM General Partner are officers of Equitrans Midstream and devote their time to EQM's business and affairs that is required to manage and conduct its operations. The daily business operations of EQM are conducted by employees of Equitrans Midstream and its subsidiaries. Under the terms of the ETRN Omnibus Agreement, EQM reimburses Equitrans Midstream for the provision of general and administrative services for its benefit, for direct expenses incurred by Equitrans Midstream on EQM's behalf and for expenses allocated to EQM as a result of it being a public entity. Additionally, EQM has a secondment agreement with Equitrans Midstream whereby Equitrans Midstream and its subsidiaries provide seconded employees to perform certain operating and other services with respect to EQM's business. Prior to the Separation, the daily business operations of EQM were conducted by employees of EQT and its subsidiaries. EQM reimbursed EQT for the provision of general and administrative services for its benefit, for direct expenses incurred by EQT on EQM's behalf and for expenses allocated to EQM as a result of it being a public entity. See Note
6
for further discussion.
Availability of Reports
EQM makes certain filings with the SEC, including its 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 its website, www.eqm-midstreampartners.com, as soon as reasonably practicable after they are filed with or furnished to the SEC. The filings are also available at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549, by calling 1-800-SEC-0330 and on the SEC's website at www.sec.gov.
Jurisdiction and Year of Formation
EQM Midstream Partners, LP (formerly EQT Midstream Partners, LP) is a Delaware limited partnership formed in January 2012.
Item 1A. Risk Factors
In addition to the other information contained in this Annual Report on Form 10-K, the following risk factors should be considered in evaluating our business and future prospects. The following discussion of risk factors contains forward-looking statements. These risk factors may be important for understanding any statement in this Annual Report on Form 10-K or elsewhere. The following information should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation" and the financial statements and accompanying notes included in "
Item 8. Financial Statements and Supplementary Data
." Note that additional risks not presently known to us or that are currently considered immaterial may also have a negative impact on our business and operations. If any of the events or circumstances described below actually occurs, our business, financial condition, results of operations, liquidity or ability to pay distributions could suffer and the trading price of our common units could decline.
Because of the following factors, as well as other variables affecting our results of operations, past financial performance may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods.
Risks Inherent in Our Business
We depend on EQT for a substantial majority of our revenues and future growth
. For example, our water service business is directly associated with EQT's well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well
. Therefore, we are subject to the business risks of EQT
, and any further decrease in EQT's drilling or completion activity could adversely affect our business and operating results
. We have no control over EQT's business decisions and operations, and EQT is under no obligation to adopt a business strategy that favors us.
Historically, we have provided a substantial percentage of our natural gas gathering, transmission and storage
and water
services to EQT. EQT accounted for approximately
74%
of our revenues for the year ended December 31, 2018. We expect to derive a substantial majority of our revenues from EQT for the foreseeable future.
For example, our ability to maintain water service revenues is substantially dependent on continued completion activity by EQT and other customers over time, including the volume of fresh water it distributes and produced water it handles for customers. Our fresh water distribution services, which make up a substantial portion of its water service revenues, will be in greatest demand in connection with completion
activities. To the extent that EQT or other fresh water distribution customers complete fewer wells, or wells with shorter lateral lengths, the demand for our fresh water distribution services would be reduced from that needed for more wells and longer lateral lengths. In addition, our fresh water distribution business is dependent upon active development in our areas of operation. In order to maintain or increase throughput levels on our fresh water distribution systems, we must service new wells. If reductions in development activity result in our inability to maintain the current levels of throughput on our water services, or if reductions in lateral lengths result in a decrease in demand for our water services on a per well basis, those reductions could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Therefore, any event, whether in our areas of operations or otherwise, that adversely affects EQT's production, financial condition, leverage, results of operations or cash flows may adversely affect our ability to sustain or increase cash distributions to our unitholders. Accordingly, we are subject to the business risks of EQT, including the following:
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prevailing and projected natural gas, NGLs and oil prices;
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the proximity, capacity, cost and availability of gathering and transportation facilities, and other factors that result in differentials to benchmark prices;
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natural gas price volatility or a sustained period of lower commodity prices may have an adverse effect on EQT's drilling operations, revenue, profitability, future rate of growth
, credit worthiness
and liquidity;
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a further reduction in or slowing of EQT's anticipated drilling and production schedule, which would directly and adversely impact demand for our services;
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the costs of producing natural gas and the availability and costs of drilling rigs and crews and other equipment;
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infrastructure capacity constraints and interruptions;
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geologic considerations;
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risks associated with the operation of EQT's wells and facilities, including potential environmental liabilities;
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the availability
and cost
of capital on a satisfactory economic basis to fund EQT's operations;
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EQT's ability to identify exploration, development and production opportunities based on market conditions;
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uncertainties inherent in projecting future rates of production
, levels of reserves, and demand for natural gas, NGLs and oil
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EQT's ability to develop additional reserves that are economically recoverable, to optimize existing well production and to sustain production;
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adverse effects of governmental and environmental regulation,
including the availability of drilling permits, the regulation of hydraulic fracturing, the potential removal of certain federal income tax deductions with respect to natural gas and oil exploration and development or additional state taxes on natural gas extraction,
changes in tax laws and negative public perception regarding EQT's operations;
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the loss of key personnel; and
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risk associated with cyber security threats.
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On January 22, 2019, EQT publicly announced a 2019 capital expenditure forecast of $1.9 billion to $2.0 billion, compared to 2018 capital expenditures of $2.4 billion.
EQT may further reduce its capital spending in the future based on commodity prices or other factors. Unless we are successful in attracting significant new customers, our ability to maintain or increase the capacity subscribed and volumes transported under service arrangements on our gathering
,
transmission and storage
and water
systems will be dependent on receiving consistent or increasing commitments from EQT. While EQT has dedicated certain acreage to, and
executed
long-term firm gathering and transmission contracts on, our systems, it may determine in the future that drilling in areas outside of our current areas of operations is strategically more attractive to it and it is under no contractual obligation to maintain its production dedicated to us. Moreover, in connection with the Separation, EQT previously disclosed publicly that EQT's strategy was transitioning from one focused on volume growth to one focused on capital efficiency and free cash flow generation and that EQT was evaluating the long-term pace of development of its Upstream Business in order to achieve the optimal balance between free cash flow generation and volume growth. Based on this evaluation and as EQT publicly disclosed, EQT is currently targeting mid-single digit annual production growth over the next five years. A reduction in
the capacity subscribed or volumes transported or gathered on our systems by EQT could have a material adverse effect on our business, financial condition, results of operations,
liquidity and our ability to make quarterly cash distributions to our unitholders.
EQT may also elect to reduce its drilling activity if commodity prices decrease. Fluctuations in energy prices can also greatly affect the development of EQT's reserves. In general terms, the prices of natural gas, oil 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 conditions, weather conditions and seasonal trends, the levels of domestic production and consumer demand, the levels of imported and exported natural gas, oil and LNG, the availability of transportation systems with adequate capacity, the volatility and uncertainty of regional pricing differentials, the price and availability of alternative fuels, the effect of energy conservation measures, the nature and extent of governmental regulation and taxation, and the anticipated future prices of natural gas, oil, LNG and other commodities. Declines in commodity prices could have a negative impact on EQT's development and production activity, and if sustained, could lead to a material decrease in such activity. Sustained reductions in development or production activity in our areas of operation could lead to reduced utilization of our services, which could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Due to these and other factors, even if reserves are known to exist in areas serviced by our assets, producers have chosen, and may choose in the future, not to develop those reserves.
The amount of cash we have available for distribution to unitholders depends primarily on our cash flow 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 flow 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 record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.
In order to pay the announced fourth quarter 2018 distribution of
$1.13
per unit, or
$4.40
per unit on an annualized basis, we will require available cash (as defined in Note 8 to the consolidated financial statements) of approximately
$211.3 million
per quarter, or
$753.2 million
per year, based on the number of common and general partner units and the IDRs outstanding at December 31, 2018. We may not have sufficient available cash each quarter to enable us to pay the quarterly cash distribution. 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:
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the rates we charge for our gathering, transmission and storage services;
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the level of firm gathering, transmission and storage capacity sold and volumes of natural gas we gather, transport and store for our customers;
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regional, domestic and foreign supply and perceptions of supply of natural gas; the level of demand and perceptions of demand in our end-use markets; and actual and anticipated future prices of natural gas and other commodities (and the volatility thereof), which may impact our ability to renew and replace firm gathering, transmission and storage agreements;
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the effect of seasonal variations in temperature on the amount of natural gas that we gather, transport and store;
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the level of competition from other midstream energy companies in our geographic markets;
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the creditworthiness of our customers;
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restrictions contained in our joint venture agreements;
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the level of our operating, maintenance and general and administrative costs;
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regulatory action affecting the supply of, or demand for, natural gas, the rates we can charge on our assets, how we contract for services, our existing contracts, our operating costs or our operating flexibility; and
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prevailing economic conditions.
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In addition, the actual amount of cash we will have available for distribution will depend on other factors, including:
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the level and timing of capital expenditures we make;
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the level of our operating and general and administrative expenses, including reimbursements to our general partner and its affiliates, including Equitrans Midstream, for services provided to us;
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the cost of our acquisitions, if any;
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our debt service requirements and other liabilities;
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fluctuations in our working capital needs;
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our ability to borrow funds and access capital markets on satisfactory terms;
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restrictions on distributions contained in our debt agreements;
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the amount of cash reserves established by our general partner; and
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other business risks affecting our cash levels.
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The demand for the services provided by our water distribution business could decline as a result of several factors.
Our water service business includes fresh water distribution for use in our customers' natural gas, NGLs and oil exploration and production activities. Water is an essential component of natural gas, NGLs and oil production during the drilling, and in particular, the hydraulic fracturing process. As a result, the demand for our fresh water distribution and produced water handling services is tied to the level of drilling and completion activity of our customers, including EQT, which is currently and anticipated to continue to be our primary customer for such services. More specifically, the demand for our water distribution and produced water handling services could be adversely affected by any further reduction in or slowing of EQT's or other customers' well completions, any reduction in produced water attributable to completion activity, or the extent to which EQT or other customers complete wells with shorter lateral lengths, which would lessen the volume of fresh water required for completion activity. In addition, increased regulation of hydraulic fracturing could result in reductions or delays in natural gas, NGLs and oil production by our water service customers, which could reduce the number of wells for which we provide water services.
The availability of our water supply may be limited due to reasons including, but not limited to, prolonged drought or regulatory delays associated with infrastructure development. Restrictions on the ability to obtain water or changes in wastewater disposal requirements may incentivize water recycling efforts by oil and natural gas producers, which could decrease the demand for our fresh water distribution services.
Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
Our interstate natural gas transmission and storage operations are regulated by the FERC under the NGA, the NGPA and the Energy Policy Act of 2005. Certain portions of our gathering operations are also rate-regulated by the FERC in connection with our interstate transmission operations. Our FERC-regulated systems operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms and terms and conditions of service to our customers. Generally, the FERC's authority extends to:
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rates and charges for natural gas transmission and storage and FERC-regulated gathering services;
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certification and construction of new interstate transmission and storage facilities;
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abandonment of interstate transmission and storage services and facilities;
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maintenance of accounts and records;
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relationships between pipelines and certain affiliates;
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terms and conditions of services and service contracts with customers;
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depreciation and amortization policies;
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acquisitions and dispositions of interstate transmission and storage facilities; and
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initiation and discontinuation of interstate transmission and storage services.
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Interstate pipelines may not charge rates or impose terms and conditions of service that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. The recourse rate that may be charged by our interstate pipeline for its transmission and storage services is established through the FERC's ratemaking process. The maximum applicable recourse rate and terms and conditions for service are set forth in our FERC-approved tariffs.
Pursuant to the NGA, existing interstate transmission and storage rates and terms and conditions of service may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases and changes to terms and conditions of service proposed by a regulated interstate pipeline may be protested and such increases or changes can be delayed and may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) "recourse rates," which are the maximum rates an interstate pipeline may charge for its services under its tariff, (ii) "discount rates," which are rates below the "recourse rates" and above a minimum level, (iii) "negotiated rates," which involve rates above or below the "recourse rates," provided that the affected customers are willing to agree to such rates and that the FERC has approved the negotiated rate agreement, and (iv) market-based rates for some of our storage services from which we derive a small portion of our revenues. As of December 31, 2018, approximately
86%
of the contracted firm transmission capacity
our system
was committed under such "negotiated rate" contracts, rather than recourse, discount or market rate contracts. There can be no guarantee that we will be allowed to continue to operate under such rate structures for the remainder of those assets' operating lives. Any successful challenge against rates charged for our transmission and storage services could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
While the FERC does not generally regulate the rates and terms of service over facilities determined to be performing a natural gas gathering function, the FERC has traditionally regulated rates charged by interstate pipelines for gathering services performed on the pipeline's own gathering facilities when those gathering services are performed in connection with jurisdictional interstate transmission facilities. We maintain rates and terms of service in our tariff for unbundled gathering services performed on a portion of our gathering facilities that are connected to our transmission and storage system. Just as with rates and terms of service for transmission and storage services, our rates and terms of services for our FERC-regulated gathering services may be challenged by complaint and are subject to prospective change by the FERC. Rate increases and changes to terms and conditions of service which we propose for our FERC-regulated gathering services may be protested, and such increases or changes can be delayed and may ultimately be rejected by the FERC.
The FERC's jurisdiction extends to the certification and construction of interstate transmission and storage facilities, including, but not limited to, acquisitions, facility maintenance, expansions, and abandonment of facilities and services. While the FERC exercises jurisdiction over the rates and terms of service for our FERC-regulated gathering services, these gathering facilities are not subject to the FERC's certification and construction authority. Prior to commencing construction of new or existing interstate transmission and storage facilities, an interstate pipeline must obtain a certificate authorizing the construction, or file to amend its existing certificate, from the FERC.
On April 19, 2018, the FERC issued a Notice of Inquiry seeking information regarding whether, and if so how, it should revise its approach under its currently effective policy statement on the certification of new natural gas transportation facilities. The formal comment period in this proceeding closed on July 25, 2018. We cannot currently predict when the FERC will issue an order in the Notice of Inquiry proceeding or what action the FERC may take in any such order. If the FERC changes its existing certificate policy, it could impact our ability to construct interstate pipeline facilities. Further, typically
a significant expansion project requires review by a number of governmental agencies, including state and local agencies, whose cooperation is important in completing the regulatory process on schedule. Any agency's delay in the issuance of, or refusal to issue, authorizations or permits for one or more of these projects may mean that we will not be able to pursue these projects or that they will be constructed in a manner or with capital requirements that we did not anticipate. Such delays, refusals or resulting modifications to projects could materially and negatively impact the revenues and costs expected from these projects or cause us to abandon planned projects.
FERC regulations also extend to the terms and conditions set forth in agreements for transmission and storage services executed between interstate pipelines and their customers. These service agreements are required to conform, in all material respects, with the forms of service agreements set forth in the pipeline's FERC-approved tariff. Non-conforming agreements must be filed with, and accepted by, the FERC. In the event that the FERC finds that an agreement is materially non-conforming, in whole or in part, it could reject the agreement or require us to seek modification, or alternatively require us to modify our tariff so that the non-conforming provisions are generally available to all customers.
On March 15, 2018, the FERC issued an order prohibiting
master limited partnership
(MLP)- owned pipelines from including an allowance for investor income tax liability in their cost-of-service based rates. Under its prior policy, the FERC had permitted all interstate pipelines to include an income tax allowance in the cost-of-service used as the basis for calculating their regulated rates. On July 18, 2018, the FERC issued an order affirming the principal finding in the March order regarding income tax recovery and also clarifying the treatment of ADIT in light of the prohibition on MLP income tax allowances. Challenges to these orders are currently pending in a consolidated proceeding before the U.S. Court of Appeals for the District
of Columbia Circuit. On October 17, 2018, an intervenor filed a motion to hold the proceeding in abeyance. On October 24, 2018, the FERC filed a motion to dismiss the proceeding. The court has not acted on either motion at this time. We cannot currently predict when the court will act on these motions or the broader proceeding, or what actions the court may take. Also, on July 18, 2018, the FERC issued Order No. 849, adopting regulations requiring that natural gas pipelines must make a one-time report, Form 501-G, due in the fourth quarter of 2018. For MLP-owned pipelines, the Form 501-G report must calculate an earned rate of return on equity that addresses any potential over-recovery of their cost of service arising from the prohibition of the income tax allowance and the ADIT clarification. On December 28, 2018, Equitrans, L.P. filed its Form 501-G with the FERC. The FERC will evaluate these Form 501-G filings on a case-by-case basis and may open a limited or a general rate case, open an investigation, or take no further action. The FERC has initiated rate cases against at least four pipelines as a result of their respective Form 501-G filings. We cannot determine whether the FERC or any customer will initiate a rate case against Equitrans, L.P. as a result of its Form 501-G filing or for any other reason. Rehearing of Order No. 849 has been requested and is currently pending before the FERC. We cannot currently predict when the FERC will issue an order on rehearing in this proceeding or what action the FERC may take in any such order. This recent action by the FERC could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to unitholders, including us.
The FERC may not continue to pursue its approach of pro-competitive policies as it considers matters such as interstate pipeline rates and rules and policies that may affect rights of access to natural gas transmission capacity and transmission and storage facilities.
Section 1(b) of the NGA exempts certain natural gas gathering facilities from regulation by the FERC under the NGA. We believe that our high-pressure natural gas gathering pipelines meet the traditional tests the FERC has used to establish a pipeline's status as an exempt gatherer not subject to regulation as a natural gas company, although the FERC has not made a formal determination with respect to the jurisdictional status of those facilities. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is often the subject of litigation within the industry, so the classification and regulation of our high-pressure gathering systems are subject to change based on future determinations by the FERC, the courts or the U.S. Congress.
Failure to comply with applicable provisions of the NGA, the NGPA, federal pipeline safety laws and certain other laws, as well as with the regulations, rules, orders, restrictions and conditions associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties. For example, the FERC is authorized to impose civil penalties of up to approximately $1.2 million per violation, per day for violations of the NGA, the NGPA or the rules, regulations, restrictions, conditions and orders promulgated under those statutes. This maximum penalty authority established by statute will continue to be adjusted periodically for inflation.
In addition, future federal, state or local legislation or regulations under which we will operate our natural gas gathering, transmission and storage businesses may have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Any significant decrease in production of natural gas in our areas of operation could adversely affect our business and operating results and reduce our cash available to make distributions.
Our business is dependent on the continued availability of natural gas production and reserves in our areas of operation. A sustained low
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price environment for natural gas or regulatory limitations could adversely affect development of additional reserves and production that is accessible by our pipeline and storage assets and fresh water sources. Production from natural gas wells will naturally decline over time. The amount of natural gas reserves underlying these wells may also be less than anticipated, and the rate at which production from these reserves declines may be greater than anticipated. Additionally, producers may determine in the future that drilling activities in areas outside of our current areas of operations are strategically more attractive to them due to the price environment for natural gas or other reasons. A reduction in the natural gas volumes supplied by producers could result in reduced throughput on our systems and adversely impact our ability to grow our operations and increase quarterly cash distributions to our unitholders. Accordingly, to maintain or increase the contracted capacity or the volume of natural gas gathered, transported and stored on our systems and cash flows associated therewith, our customers must continually access additional reserves of natural gas.
The primary factors affecting our ability to obtain non-dedicated sources of natural gas include the level of successful drilling activity near our systems and our ability to compete for volumes from successful new wells. While EQT has dedicated production from certain of its leased properties to us, 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 gathering systems or the rate at which production from a well declines. In addition, we have no control over EQT or other producers or their drilling or production decisions, which are affected by, among other things, the availability and cost of capital, prevailing and projected energy prices, demand for
hydrocarbons, levels of reserves, the producer's contractual obligations to us and other midstream companies, geological considerations, environmental or other governmental regulations, the availability of drilling permits, the availability of drilling rigs and crews, and other production and development costs.
Fluctuations in energy prices can also greatly affect the development of new natural gas reserves. In general terms, the prices of natural gas, oil 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. For example, the daily spot prices for NYMEX Henry Hub natural gas ranged from a high of
$7.13
per MMBtu to a low of
$2.44
per MMBtu from January 1,
2017
through December 31
, 2018.
Factors affecting natural gas prices include worldwide economic conditions; weather conditions and seasonal trends; the levels of domestic production and consumer demand; new exploratory finds of natural gas; the availability of imported, and the ability to export, natural gas and LNG; the availability of transportation systems with adequate capacity; the volatility and uncertainty of regional basis differentials and premiums; the price and availability of alternative fuels; the effects of energy conservation measures; the nature and extent of governmental regulation and taxation; and the anticipated future prices of natural gas, oil, LNG and other commodities. Low natural gas prices, particularly in the Appalachian Basin, have had a negative impact on exploration, development and production activity and, if sustained, could lead to a material decrease in such activity. Sustained reductions in exploration or production activity in our areas of operation would lead to reduced utilization of our systems. Because of these factors, even if new natural gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Moreover, EQT may not develop the acreage it has dedicated to us. If reductions in drilling activity result in our inability to maintain levels of contracted capacity and throughput, it could reduce our revenue and impair our ability to make quarterly cash distributions to our unitholders.
We do not obtain independent evaluations of natural gas reserves connected to our systems. Accordingly, we do not have independent estimates of total reserves connected to our systems or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our systems are less than we anticipate, or the timeline for the development of reserves is longer than we anticipate, and we are unable to secure additional sources of natural gas, there could be a material adverse effect on our business, results of operations, financial condition, liquidity and ability to make quarterly cash distributions to our unitholders.
If new supplies of natural gas are not obtained to replace the natural decline in volumes from existing supply basins in our area of operation, or if natural gas supplies are diverted to serve other markets, the overall volume of natural gas gathered, transported and stored on our systems would decline, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Additionally, see ''
We depend on EQT for a substantial majority of our revenues and future growth. For example, our water service business is directly associated with EQT's well completion activities and water needs, which are partially driven by horizontal lateral lengths and the number of completion stages per well. Therefore, we are subject to the business risks of EQT, and any further decrease in EQT's drilling or completion activity could adversely affect our business and operating results. We have no control over EQT's business decisions and operations, and EQT is under no obligation to adopt a business strategy that favors us
.''
The lack of diversification of our assets and geographic locations could adversely affect our ability to make distributions to our unitholders.
We rely exclusively on revenues generated from our gathering, transmission and storage and water systems, which are primarily located in the Appalachian Basin in Pennsylvania, West Virginia and Ohio. Due to our lack of diversification in assets and geographic location, an adverse development in these businesses or our areas of operations, including adverse developments due to catastrophic events, weather, regulatory action and decreases in demand for natural gas, could have a more significant impact on our results of operations and distributable cash flow to our unitholders than if we maintained more diverse assets and locations.
We may not be able to increase our customer throughput and resulting revenue due to competition and other factors, which could limit our ability to grow.
Part of our growth strategy includes diversifying our customer base by identifying opportunities to offer services to parties other than EQT. For the years ended
December 31, 2018
, 2017 and 2016, EQT accounted for approximately
80%
,
88%
and
96%
, respectively, of our gathering revenues and approximately
54%
,
54%
and
51%
, respectively, of our transmission and storage revenues. For the year ended
December 31, 2018
and for the period from November 13, 2017 through December 31, 2017, EQT accounted for approximately
93%
and
99%
of our water service revenues, respectively. EQT accounted for approximately
74%
,
74%
and
75%
of our total revenues for the years ended
December 31, 2018
,
2017
and
2016
, respectively. Our ability to increase our customer-subscribed capacity and throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third-party producers' existing contractual obligations to competitors and the
extent to which we have available capacity when shippers require it. To the extent that we lack available capacity on our systems for volumes, we may not be able to compete effectively with third-party systems for additional natural gas production in our areas of operation.
We have historically provided gathering, transmission, storage and water services to parties
other than EQT
on only a limited basis and may not be able to attract material service opportunities. Our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to long-term firm contracts. Our potential customers may prefer to obtain services under other forms of contractual arrangements under which we would be required to assume direct commodity exposure. In addition, we must continue to improve our reputation among our potential customer base for providing high quality service to successfully attract
new customers
.
The regulatory approval process for the construction of new midstream assets is challenging, and recent decisions by regulatory and judicial authorities in pending proceedings could impact EQM's or the MVP Joint Venture's ability to obtain all approvals and authorizations necessary to complete certain projects on the projected time frame or at all or EQM's ability to achieve the expected investment return on the project.
Certain of our internal growth projects may require regulatory approval from federal, state and local authorities prior to construction, including any extensions from or additions to its transmission and storage system. The approval process for storage and transportation projects has become increasingly challenging, due in part to state and local concerns related to exploration and production, transmission and gathering activities in new production areas, including the Marcellus, Utica and Upper Devonian Shales, and negative public perception regarding the oil and gas industry, including major pipeline projects like the MVP. Such authorization may not be granted or, if granted, such authorization may include burdensome or expensive conditions.
In addition, any significant delays in the regulatory approval process for the MVP project could increase costs and negatively impact the scheduled in-service date of fourth quarter 2019, which in turn could adversely affect the ability for the MVP Joint Venture and its owners, including us, to achieve the expected investment return. The MVP project is subject to several challenges that must be resolved before the MVP project can be completed, as described in more detail in "Item 3. Legal Proceedings."
Although the MVP Joint Venture is actively defending the relevant agency actions and judicial challenges to the project, and is in active dialogue with all of the affected agencies to resolve these issues and restore the affected permits, there is no guarantee as to how long the agency proceedings and judicial challenges will take to resolve, or whether the MVP Joint Venture will ultimately succeed in restoring the permits in their present form or within the MVP Joint Venture's targeted time frame for placing the project in service. This and other similar litigation could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We are exposed to the credit risk of our counterparties in the ordinary course of our business.
We are exposed to the risk of loss resulting from the nonpayment and/or nonperformance of our customers, suppliers, joint venture partners and other counterparties. We extend credit to our customers, including EQT as our largest customer, as a normal part of our business. While we have established credit policies, including assessing the creditworthiness of our customers as permitted by our FERC-approved natural gas tariffs, and requiring appropriate terms or credit support from them based on the results of such assessments, we may not have adequately assessed the creditworthiness of our existing or future customers.
We cannot predict the extent to which the businesses of
our counterparties
, including EQT,
would be impacted if commodity prices decline, commodity prices are depressed for a sustained period of time, or other conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on the abilities of our counterparties to perform under their gathering, transmission and storage
and water service
agreements with us. 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 one or more of our customers 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 resulting nonpayment and/or nonperformance by our counterparties could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Increased competition from other companies that provide gathering, transmission and storage
, and water
services, or from alternative fuel sources, could have a negative impact on the demand for our services, which could adversely affect our financial results.
Our ability to renew or replace existing contracts at rates sufficient to maintain current revenues and cash flows could be adversely affected by the activities of our competitors. Our systems compete primarily with other interstate and intrastate
pipelines and storage facilities in the gathering, transmission and storage of natural gas. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of natural gas or water than we do. Some of these competitors may expand or construct gathering systems
,
transmission and storage systems
and water systems
that would create additional competition for the services we provide to our customers. In addition, our customers may develop their own gathering, transmission or storage
, or water
services instead of using ours. Moreover, none of
Equitrans Midstream,
EQT or any of their respective affiliates is limited in its ability to compete with us.
The policies of the FERC promoting competition in natural gas markets are having the effect of increasing the natural gas transmission and storage options for our traditional customer base. As a result, we could experience some "turnback" of firm capacity as existing agreements expire. If we are unable to remarket this capacity or can remarket it only at substantially discounted rates compared to previous contracts, we may have to bear the costs associated with the turned back capacity. Increased competition could reduce the volumes of natural gas transported or stored on our system or, in cases where we do not have long-term firm contracts, could force us to lower our transmission or storage rates. Increased competition could also adversely affect demand for EQM's water services.
Further, natural gas as a fuel competes with other forms of energy available to end-users, including coal, liquid fuels and renewable and alternative energy. Increased demand for such forms of energy at the expense of natural gas could lead to a reduction in demand for natural gas gathering, transmission and storage
, and water
services.
All of these competitive pressures could make it more difficult for us to retain our existing customers and/or attract new customers as we seek to expand our business, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. In addition, competition could intensify the negative impact of factors that decrease demand for natural gas in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of natural gas.
If third party pipelines and other facilities interconnected to our pipelines and facilities become unavailable to transport or process natural gas, our revenues and cash available to make distributions to our unitholders could be adversely affected.
We depend on third
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party pipelines and other facilities that provide receipt and delivery options to and from our transmission and storage system. For example, our transmission and storage system interconnects with the following interstate pipelines: Texas Eastern, Dominion Transmission, Columbia Gas Transmission, Tennessee Gas Pipeline Company, Rockies Express Pipeline LLC
,
National Fuel Gas Supply Corporation
and ET Rover Pipeline, LLC
, as well as multiple distribution companies. Similarly, our gathering systems have multiple delivery interconnects to multiple interstate pipelines. In the event that our access to such systems was impaired, the amount of natural gas that our gathering systems can gather and transport would be adversely affected, which could reduce revenues from our gathering activities. Because we do not own these third
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party pipelines or facilities, their continuing operation is not within our control. If these or any other pipeline connections or facilities were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to operate efficiently and continue shipping natural gas to end markets could be restricted. Any temporary or permanent interruption at any key pipeline interconnect or facility could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Certain of the services we provide on our transmission and storage system are subject to long-term, fixed-price "negotiated rate" contracts that are not subject to adjustment, even if our cost to perform such services exceeds the revenues received from such contracts, and, as a result, our costs could exceed our revenues received under such contracts.
It is possible that costs to perform services under "negotiated rate" contracts will exceed the negotiated rates we have agreed to provide to our customers. If this occurs, it could decrease the cash flow realized by our systems and, therefore, the cash we have available for distribution to our unitholders. Under FERC policy, a regulated service provider and a customer may mutually agree to a "negotiated rate," and that contract must be filed with and accepted by the FERC. As of December 31, 2018, approximately
86%
of the contracted firm transmission capacity on our system was subscribed under such "negotiated rate" contracts. Unless the parties to these "negotiated rate" contracts agree otherwise, the contracts generally may not be adjusted to account for increased costs that could be caused by inflation or other factors relating to the specific facilities being used to perform the services.
We may not be able to renew or replace expiring contracts at favorable rates or on a long-term basis.
Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal.
Based on total projected contractual revenues, including projected contractual revenues from future capacity expected
from expansion projects that are not yet fully constructed for which EQM has executed firm contracts,
our firm gathering contracts and firm transmission and storage contracts had weighted average remaining terms of approximately
11
years and
15
years, respectively, as of
December 31, 2018
.
The extension or replacement of existing contracts, including our contracts with EQT, depends on a number of factors beyond our control, including:
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the level of existing and new competition to provide services to our markets;
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the macroeconomic factors affecting natural gas economics for our current and potential customers;
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the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
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the extent to which the customers in our markets are willing to contract on a long-term basis; and
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the effects of federal, state or local regulations on the contracting practices of our customers.
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Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
If the tariffs governing the services we provide are successfully challenged, we could be required to reduce our tariff rates, which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Rate payers, the FERC or other interested stakeholders, such as state regulatory agencies, may challenge our rates offered to individual customers or the terms and conditions of service included in our tariffs. We do not have an agreement in place that would prohibit customers, including EQT or its affiliates, from challenging our tariffs. If any challenge were successful, among other things, the rates that we charge on our systems could be reduced. Successful challenges could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. See
"Our natural gas gathering, transmission and storage services are subject to extensive regulation by federal, state and local regulatory authorities. Changes or additional regulatory measures adopted by such authorities could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions."
If we do not complete expansion projects, our future growth may be limited.
A significant component of our growth strategy is to continue to grow the cash distributions on our units by expanding our business. Our ability to grow depends, in part, upon our ability to complete expansion projects
, including, without limitation, the MVP, MVP Southgate and Hammerhead projects,
that result in an increase in the cash we generate. We may be unable to complete successful, accretive expansion projects for many reasons, including, but not limited to, the following:
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an inability to identify attractive expansion projects;
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an inability to obtain necessary rights-of-way, real-estate rights or permits or other government approvals, including approvals by regulatory agencies, whether as a result of further government shutdowns or otherwise;
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an inability to successfully integrate the infrastructure we build;
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an inability to raise financing for expansion projects on economically acceptable terms;
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incorrect assumptions about volumes, revenues and costs, including potential growth; or
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an inability to secure adequate customer commitments to use the newly expanded facilities.
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In addition, our ability to secure required permits and rights-of-way or otherwise proceed with construction of our expansion projects could encounter opposition from political activists, who may attempt to delay pipeline construction through protests and other means, as has recently occurred to the MVP.
Expanding our business by constructing new midstream assets subjects us to risks.
Organic and greenfield growth projects are a significant component of our growth strategy. The development and construction of pipelines and storage facilities involves numerous regulatory, environmental, political and legal uncertainties beyond our control and will require the expenditure of significant amounts of capital. The development and construction of pipeline infrastructure and storage facilities expose us to construction risks such as the failure to meet customer contractual
requirements, delays caused by landowners or advocacy groups opposed to the
natural
gas industry, environmental hazards,
adverse weather conditions,
the performance of third-party contractors, the lack of available skilled labor, equipment and materials and the inability to obtain necessary rights-of-way or approvals and permits from regulatory agencies on a timely basis or at all (and maintain such rights of way, approvals and permits once obtained). These types of projects may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase for some time after completion of a particular project. For instance, we will be required to pay construction costs generally as they are incurred but construction will typically occur over an extended period of time, and we will not receive
revenues or
material increases in revenues until the project is placed into service. Moreover, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We may face opposition to the development or operation of our pipelines and facilities from various groups.
We may face opposition to the development 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, including Equitrans Midstream, and, accordingly, adversely affect our financial condition and the market price of our securities.
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 financial institutions, funds and other sources of capital restricting or eliminating their investment in energy-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.
Acquisitions we may make could reduce, rather than increase, our cash generated from operations on a per unit basis.
If we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from operations on a per unit basis.
Any acquisition involves potential risks, including, among other things:
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mistaken assumptions about volumes, revenues and costs, including synergies and potential growth;
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an inability to secure adequate customer commitments to use the acquired systems or facilities;
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an inability to integrate successfully the assets or businesses we acquire;
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the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;
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the diversion of management's and employees' attention from other business concerns; and
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unforeseen difficulties operating in new geographic areas or business lines.
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If any acquisition fails to be accretive to our distributable cash flow per unit, it could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Review of our goodwill has resulted in and could result in future significant impairment charges.
GAAP requires us to perform an assessment of goodwill at the reporting unit level for impairment at least annually and whenever events or changes in circumstance indicate that the fair value of a reporting unit is less than its carrying amount.
We may perform either a qualitative or quantitative assessment of potential impairment. Our qualitative assessment of potential impairment may result in the determination that a quantitative impairment analysis is not necessary. Under this elective process,
we assess qualitative factors to determine whether the existence of events or circumstances leads us to determine that it is more likely than not that the fair value of a reporting unit is less than its carrying amount. If after assessing the totality of events or circumstances, we determine that it is more likely than not that the fair value of a reporting unit is greater than its carrying amount, then performing a quantitative analysis is not required. However, if we conclude otherwise, then we perform a quantitative impairment analysis. If we choose not to perform a qualitative assessment, or if we choose to perform a qualitative assessment but are unable to qualitatively conclude that no impairment has occurred, then we will perform a quantitative evaluation. In the case of a quantitative assessment, we estimate the fair value of the reporting unit with which the goodwill is associated and compare it to the carrying value. If the estimated fair value of a reporting unit is less than its carrying value, an impairment charge is recognized for the excess of the reporting unit's carrying value over its fair value.
Assessing the recoverability of goodwill requires significant judgments and estimates by management. Fair values of goodwill are primarily estimated using discounted cash flows based on forecasts of financial results that incorporate assumptions including, but not limited to, the discount rate, terminal value factor, peer groups, control premiums and earnings before interest, taxes, depreciation and amortization multiples. All of our goodwill relates to businesses that were acquired and valued by EQT's management in the Rice Merger.
Following the third quarter of 2018 and prior to the Separation, we identified impairment indicators in the form of production curtailments announced by a primary customer of the two reporting units to which our goodwill is recorded that could reduce volumetric-based fee revenues of those reporting units. For the year ended December 31, 2018, we determined that the carrying value of one of those reporting units (the RMP PA Gas Gathering reporting unit, which comprises the Pennsylvania gathering assets acquired in the Rice Merger) was greater than its fair value. As a result, we recognized impairment of goodwill of
$261.9 million
. If the operations or projected operating results of these businesses decline significantly, we could incur additional goodwill impairment charges. Future impairment charges could be significant and could have a material adverse impact on our financial condition and results of operations for the period in which the impairment is recorded. As of December 31, 2018, we had approximately
$1.1 billion
of goodwill, which will be monitored for future impairment. Management will continue to monitor and evaluate the factors underlying the fair market value of acquired businesses over the course of the year to determine if any interim assessments are necessary and will take any additional impairment charges required.
Failure to successfully combine and integrate the businesses of EQM and RMP may adversely affect the future results of the combined organization and our ability to achieve the intended benefits of the EQM-RMP Merger.
The success of the EQM-RMP Merger depends, in part, on our ability to realize the anticipated benefits from combining the businesses of EQM and RMP, and integration of the parties gathering systems remains ongoing. To realize these anticipated benefits, the businesses must be successfully combined and integrated. If the combined organization is not able to achieve these objectives, or is not able to achieve these objectives on a timely basis, the anticipated benefits of the EQM-RMP Merger may not be realized fully or at all. In addition, the ongoing integration may result in additional and unforeseen expenses, which could reduce the anticipated benefits of the EQM-RMP Merger. There can be no assurance that our combination with RMP will deliver the strategic, financial and operational benefits anticipated by us. Our business may be negatively impacted if it is unable to effectively manage its expanded operations, which could have a material adverse effect on our ability to make quarterly cash distributions to our unitholders.
If we are unable to obtain needed capital or financing on satisfactory terms to fund expansions of our asset base or acquisitions, our ability to make quarterly cash distributions may be diminished or our financial leverage could increase. We do not have any commitment with our general partner or Equitrans Midstream to provide any direct or indirect financial assistance to us.
In order to expand our asset base and complete our announced expansion projects, including the MVP
, MVP Southgate and Hammerhead projects, we
will need to make significant expansion capital expenditures and acquisition capital expenditures. If we do not make sufficient or effective capital expenditures, we will be unable to expand our business operations and may be unable to maintain or raise the level of our quarterly cash distributions.
In order to fund our expansion capital expenditures and acquisition capital expenditures, we will be required to use cash from our operations, incur borrowings or sell additional common units or other partner interests. Using cash from operations will reduce distributable cash flow to our common unitholders. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition at the time of any such financing or offering, the covenants in our debt agreements, general economic conditions and contingencies and uncertainties that are beyond our control. 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 equity in the capital markets. Even if we are successful in obtaining funds for expansion and acquisition capital expenditures through equity or debt financings, 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 partner interests may result in significant common unitholder dilution and increase the aggregate amount of cash required to maintain the then-current distribution
rates
, which could materially decrease our ability to pay distributions at the then-current distribution
rates.
If funding is not available to us when needed, or is available only on unfavorable terms, we may be unable to execute our business plans, complete acquisitions or otherwise take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. There is no commitment from our general partner or Equitrans Midstream to provide any direct or indirect financial assistance to us.
We are subject to numerous hazards and operational risks.
Our business operations are subject to all of the inherent hazards and risks normally incidental to the gathering, transmission and storage of natural gas and performance of water services. These operating risks include, but are not limited to:
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damage to pipelines, facilities, equipment
, environmental controls
and surrounding properties caused by hurricanes, earthquakes, tornadoes,
abnormal amounts of rainfall,
floods, fires, droughts, landslides and other natural disasters and acts of sabotage and terrorism;
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inadvertent damage from construction, vehicles, and farm and utility equipment;
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uncontrolled releases of natural gas and other hydrocarbons;
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leaks, migrations or losses of natural gas as a result of the malfunction of equipment or facilities and, with respect to storage assets, as a result of undefined boundaries, geologic anomalies, natural pressure migration and wellbore migration;
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ruptures, fires and explosions;
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pipeline freeze offs due to cold weather; and
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other hazards that could also result in personal injury and loss of life, pollution to the environment and suspension of operations.
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These risks could result in loss of human life, personal injuries, significant damage to property, environmental pollution, impairment of our operations, regulatory investigations and penalties and substantial losses to us. The location of certain segments 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. In spite of any precautions taken, an event such as those described above could cause considerable harm to people
,
property
or the environment
and could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. 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 segments of our systems. Potential customer impacts arising from service interruptions on segments of our systems could include limitations on our ability to satisfy customer requirements, obligations to provide reservation charge credits to customers in times of constrained capacity, and solicitation of our existing customers by others for potential new projects that would compete directly with our existing services. Such circumstances could adversely impact our ability to meet contractual obligations and retain customers, with a resulting negative impact on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Negative public perception regarding us, the MVP, MVP Southgate, our other projects and/or the midstream industry could have an adverse effect on our operations.
Negative public perception regarding us, the MVP, MVP Southgate, our other projects and/or the midstream industry resulting from, among other things, oil spills, the explosion of natural gas transmission and gathering lines, erosion and sedimentation issues, and general concerns raised by advocacy groups about hydraulic fracturing and pipeline projects has led to, and may in the future lead to, increased regulatory scrutiny, which may, in turn, lead to new local, state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. See "Item 3. Legal Proceedings." These actions have caused, and may continue to cause, operational delays or restrictions, increased construction and operating costs, penalties under construction contracts, additional regulatory burdens and increased risk of litigation. As discussed under "
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The regulatory approval process for the construction of new midstream assets is challenging, and recent decisions by regulatory and judicial authorities in pending proceedings could impact EQM's or the MVP Joint Venture's ability to obtain all approvals and authorizations necessary to complete certain projects on the projected time frame or at all or
EQM's ability to achieve the expected investment return on the project
," there are several pending challenges to certain aspects of the MVP project that must be resolved before the MVP project can be completed. 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 and the MVP Joint Venture need to conduct our operations to be removed, withheld, delayed or burdened by requirements that restrict our ability to profitably conduct business.
We do not insure against all potential losses and could be seriously harmed by unexpected liabilities.
We are not fully insured against all risks inherent in our business, including environmental accidents that might occur. In addition, we do not maintain business interruption insurance of the types and in amounts necessary to cover all possible risks of loss, like project delays caused by governmental action or inaction. The occurrence of any operating risks not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Equitrans Midstream currently maintains excess liability insurance that covers Equitrans Midstream and its affiliates, including our, legal and contractual liabilities arising out of bodily injury, personal injury or property damage, including resulting loss of use, to third parties. This excess liability insurance includes coverage for sudden and accidental pollution liability but excludes: release of pollutants subsequent to their disposal; release of substances arising from the combustion of fuels that result in acidic deposition; and testing, monitoring, clean-up, containment, treatment or removal of pollutants from property owned, occupied by, rented to, used by or in the care, custody or control of Equitrans Midstream and its affiliates, including us.
Equitrans Midstream also
maintains
coverage for
us
and
our
affiliates, for physical damage to assets and resulting business interruption, including damage caused by terrorist acts.
All of Equitrans Midstream's insurance is subject to deductibles
or self-insured retentions
. If a significant accident or event occurs for which
Equitrans Midstream is
not fully insured, it could adversely affect
our
operations and financial condition. Equitrans Midstream may not be able to maintain or obtain insurance
for itself and its affiliates,
of the types and in the amounts we desire at reasonable rates, and Equitrans Midstream may elect to self-insure a portion of EQM's asset portfolio. The insurance coverage Equitrans Midstream has obtained or may obtain may contain large deductibles or fail to cover certain hazards or cover all potential losses. In addition,
for pre-Distribution losses, Equitrans Midstream will
share insurance coverage with EQT. Equitrans Midstream
will remain responsible for payment of any deductible or self-insured amounts under those insurance policies. To the extent we
experience
a pre-Distribution loss that would be
covered under
EQT's
insurance policies,
our ability to collect under those policies
may be reduced
to the extent EQT erodes the limits under those policies.
Terrorist or cyber security attacks or threats thereof aimed at our pipelines or facilities or surrounding areas and new laws and regulations governing data privacy could adversely affect our business.
Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications, to operate our assets, and the maintenance of our financial and other records has long been dependent upon such technologies. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Deliberate attacks on, or unintentional events affecting, our systems or infrastructure, the systems or infrastructure of third parties or the cloud could lead to corruption or loss of our proprietary data and potentially sensitive data, delays in delivery of natural gas and NGLs, difficulty in completing and settling transactions, challenges in maintaining our books and records, communication interruptions, environmental damage, personal injury, property damage and other operational disruptions, as well as damage to our reputation, financial condition and cash flows. Further, as cyber incidents continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. In addition, new U.S. laws and regulations governing data privacy and the unauthorized disclosure of personal information may potentially elevate our compliance costs. Any failure by us to comply with these laws and regulations, including as a result of a cyber incident, could result in significant penalties and liability to us. 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.
We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.
Our operations are regulated extensively at the federal, state and local levels. Laws, regulations and other legal requirements have increased the cost to plan, design, install, operate and abandon gathering
,
transmission
and water
systems and pipelines. Environmental, health and safety legal requirements govern discharges of substances into the air, water and ground; the management and disposal of hazardous substances and wastes; the clean-up of contaminated sites; groundwater quality and availability; plant and wildlife protection; locations available for pipeline construction; environmental impact studies and assessments prior to permitting; restoration of properties after construction or operations are completed; pipeline safety
(including replacement requirements); and work practices related to employee health and safety. Compliance with the laws, regulations and other legal requirements applicable to our business, including delays in obtaining permits or other government approvals, may increase our costs of doing business, result in delays or restrictions in the performance of operations due to the need to obtain additional or more detailed permits or other governmental approvals or even cause us not to pursue a project. For example, the U.S. Fish and Wildlife Service continues to receive hundreds of petitions to consider listing of additional species as endangered or threatened and is being regularly sued or threatened with lawsuits to address these petitions. Some of these legal actions may result in the listing of species located in areas in which we operate. Such designations of previously unprotected species as being endangered or threatened, or the designation of previously unprotected areas as a critical habitat for such species, can result in increased costs, construction delays, restrictions in our operations or abandonment of projects.
Listing of aquatic species could potentially affect water supplies or delay related infrastructure development.
In addition, compliance with laws, regulations or other legal requirements could subject us to claims for personal injuries, property damage and other damages. Our failure to comply with the laws, regulations and other legal requirements applicable to our business, even if as a result of factors beyond our control, could result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties and damages.
Laws, regulations and other legal requirements are constantly changing, and implementation of compliant processes in response to such changes could be costly and time consuming. For example, in October 2015, the
EPA
revised the NAAQS for ozone from 75 parts per billion for the current 8-hour primary and secondary ozone standards to 70 parts per billion for both standards. The EPA may designate the areas in which we operate as nonattainment areas. States that contain any areas designated as nonattainment areas will be required to develop implementation plans demonstrating how the areas will attain the applicable standard within a prescribed period of time. These plans may require the installation of additional equipment to control emissions. In addition, in May 2016, the EPA finalized rules that impose volatile organic compound emissions limits (and collaterally reduce methane emissions) on certain types of compressors and pneumatic pumps, as well as requiring the development and implementation of leak monitoring plans for compressor stations. The
EPA finalized amendments to some requirements in these standards in March 2018 and September 2018, including rescission of certain requirements and revisions to other requirements such as fugitive emissions monitoring frequency
. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. In addition to periodic changes to air, water and waste laws, as well as recent EPA initiatives to impose climate change-based air regulations on industry, the U.S. Congress and various states have been evaluating climate-related legislation and other regulatory initiatives that would further restrict emissions of
GHG
, including methane (a primary component of natural gas) and carbon dioxide (a byproduct of burning natural gas). Several states are also pursuing similar measures to regulate emissions of GHGs from new and existing sources. If implemented, such GHG restrictions may result in additional compliance obligations with respect to, or taxes on the release, capture and use of GHGs that could have an adverse effect on our operations.
There is a risk that we may incur costs and liabilities in connection with our operations due to historical industry operations and waste disposal practices, our handling of wastes and potential emissions and discharges related to our operations. Private parties, including the owners of the properties through which our gathering system or our transmission and storage system pass and facilities where our wastes are taken for reclamation or disposal, may have the right to pursue legal actions to require remediation of contamination or enforce compliance with environmental requirements as well as to seek damages for personal injury or property damage. In addition, changes in environmental laws occur frequently, and any such changes that result in more stringent and costly waste handling, storage, transport, disposal or remediation requirements could have a material adverse effect on our business, financial condition, results of operations, liquidity or ability to make quarterly cash distributions to our unitholders. We may not be able to recover all or any of these costs from insurance.
Climate change and related legislation, regulatory initiatives and litigation could result in increased operating costs and reduced demand for the natural gas services we provide.
Legislative and regulatory measures to address climate change and GHG emissions are in various phases of discussion or implementation. The EPA regulates GHG emissions from new and modified facilities that are potential major sources of criteria pollutants under the Clean Air Act's Prevention of Significant Deterioration and Title V programs and has adopted regulations that require, among other things, preconstruction and operating permits for certain large stationary sources and the monitoring and reporting of GHGs from certain onshore oil and natural gas production sources on an annual basis.
In addition, the U.S. Congress, along with federal and state agencies,
has
considered measures to reduce the emissions of GHGs. Legislation or regulation that restricts carbon emissions could increase our cost of environmental compliance by requiring us to install new equipment to reduce emissions from larger facilities and/or, depending on any future legislation, purchase emission allowances. Climate change and GHG legislation or regulation could also delay or otherwise negatively affect efforts to obtain and maintain permits and other regulatory approvals for existing and new facilities, impose additional
monitoring and reporting requirements or adversely affect demand for the natural gas we gather, transport and store. Conversely, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit us by increasing demand for natural gas because the combustion of natural gas results in substantially fewer carbon emissions per Btu of heat generated than other fossil fuels such as coal. The effect on us of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Significant portions of our pipeline systems have been in service for several decades. There could be unknown events or conditions or increased maintenance or repair expenses and downtime associated with our pipelines that could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make distributions.
Significant portions of our transmission and storage system and FERC-regulated gathering system have been in service for several decades. The age and condition of these systems could result in increased maintenance or repair expenditures, and any downtime associated with increased maintenance and repair activities could materially reduce our revenue. Any significant increase in maintenance and repair expenditures or loss of revenue due to the age or condition of our systems could adversely affect our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We may incur significant costs and liabilities as a result of increasingly stringent pipeline safety regulation, including pipeline integrity management program testing and related repairs.
The DOT, acting through
PHMSA
, has adopted regulations requiring pipeline operators to develop integrity management programs for transmission pipelines located where a leak or rupture could harm HCAs, including high population areas, unless the operator effectively demonstrates by risk assessment that the pipeline could not affect the area. The regulations require operators, including us, to:
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perform ongoing assessments of pipeline integrity;
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identify and characterize applicable threats to pipeline segments that could impact a HCA;
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maintain processes for data collection, integration and analysis;
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repair and remediate pipelines as necessary; and
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implement preventive and mitigating actions.
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Changes to pipeline safety laws and regulations that result in more stringent or costly safety standards could have a significant adverse effect on us and similarly situated midstream operators. For example, in April 2016, PHMSA published a notice of proposed rulemaking addressing several integrity management topics and proposing new requirements to address safety issues for natural gas transmission and gathering lines. The proposed rule would strengthen existing integrity management requirements, expand assessment and repair requirements to pipelines in areas with medium population densities and extend regulatory requirements to onshore gas gathering lines that are currently exempt. Further, in June 2016, then-President Obama signed
the
2016 Pipeline Safety Act that extended PHMSA's statutory mandate under prior legislation through 2019. In addition, the 2016 Pipeline Safety Act empowered PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing and also required PHMSA to develop new safety standards for natural gas storage facilities by June 2018. Pursuant to those provisions of the 2016 Pipeline Safety Act, in October 2016 and December 2016, PHMSA issued two Interim Final Rules that expanded the agency's authority to impose emergency restrictions, prohibitions and safety measures and strengthened the rules related to underground natural gas storage facilities, including well integrity, wellbore tubing and casing integrity. The December 2016 Interim Final Rule, relating to underground gas storage facilities, went into effect in January 2017, with a compliance deadline in January 2018. PHMSA determined, however, that it will not issue enforcement citations to any operators for violations of provisions of the December 2016 Interim Final Rule that had previously been non-mandatory provisions of American Petroleum Institute Recommended Practices 1170 and 1171 until one year after PHMSA issues a final rule; however, no final rule has been issued. Additionally, in January 2017, PHMSA announced a new final rule regarding hazardous liquid pipelines, which increases the quality and frequency of tests that assess the condition of pipelines, requires operators to annually evaluate the existing protective measures in place for pipeline segments in HCAs, extends certain leak detection requirements for hazardous liquid pipelines not located in HCAs, and expands the list of conditions that require immediate repair. However, it is unclear when or if this rule will go into effect because, on January 20, 2017, the Trump Administration requested that all regulations that had been sent to the Office of the Federal Register, but were not yet published, be immediately withdrawn for further review. Accordingly, this rule has not become effective through publication in the Federal Register. We are monitoring and evaluating the effect of these and other emerging requirements on our operations.
States are generally preempted by federal law in the area of pipeline safety, but state agencies may qualify to assume responsibility for enforcing federal regulations over intrastate pipelines. They may also promulgate additive pipeline safety regulations provided that the state standards are at least as stringent as the federal standards. Although many of our natural gas facilities fall within a class that is not subject to integrity management requirements, we may incur significant costs and liabilities associated with repair, remediation, preventive or mitigation measures associated with our non-exempt transmission pipelines. The costs, if any, for repair, remediation, preventive or mitigating actions that may be determined to be necessary as a result of the testing program, as well as lost cash flows resulting from shutting down our pipelines during the pendency of such actions, could be material.
Should we fail to comply with DOT regulations adopted under authority granted to PHMSA, we could be subject to penalties and fines. PHMSA has the authority to impose civil penalties for pipeline safety violations up to a maximum of approximately $200,000 per day for each violation and approximately $2 million for a related series of violations. This maximum penalty authority established by statute will continue to be adjusted periodically to account for inflation. In addition, we may be required to comply with new safety regulations and make additional maintenance capital expenditures in the future for similar regulatory compliance initiatives that are not reflected in our forecasted maintenance capital expenditures.
The adoption of legislation relating to hydraulic fracturing and the enactment of new or increased severance taxes and impact fees on natural gas production could cause our current and potential customers to reduce the number of wells they drill in the Marcellus,
Utica and
Upper Devonian Shales or curtail production of existing wells. If reductions are significant for those or other reasons, the reductions would have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Our assets are primarily located in the Marcellus Shale fairway in southwestern Pennsylvania and northern West Virginia
and the Utica Shale fairway in eastern Ohio
, and a substantial majority of the production that we receive from customers is produced from wells completed using hydraulic fracturing. Hydraulic fracturing is an important and commonly used process in the completion of oil and gas wells, particularly in unconventional resource plays like the Marcellus,
Utica and
Upper Devonian Shales. Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies, but several federal agencies have asserted regulatory authority over aspects of the process, including the EPA, which
finalized
effluent limit guidelines
allowing zero discharge of
waste water from shale gas extraction operations to a
publicly owned
treatment plant
in 2016 in addition to existing limits on direct discharges. Additionally, in response to increased public concern regarding the alleged potential impacts of hydraulic fracturing, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act (SDWA) over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance in February 2014 addressing the performance of such activities using diesel fuels. The
federal Bureau of Land Management (BLM),
has also asserted regulatory authority over aspects of the process, and
issued a final rule in March 2015 that established more stringent standards for performing hydraulic fracturing on federal and Indian lands. The BLM rule was struck down by a federal court in Wyoming in June 2016, but was reinstated on appeal by the Tenth Circuit in September 2017. While this appeal was pending, BLM proposed a rulemaking in July 2017 to rescind these rules in their entirety. BLM published a final rule rescinding the 2015 rules in December
2017. However,
other federal or state agencies may look to the BLM rule in developing new regulations that could apply to our operations.
The U.S. Congress has from time to time considered the adoption of legislation to provide for federal regulation of hydraulic fracturing, while a growing number of states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. Some states, such as Pennsylvania, have imposed fees on the drilling of new unconventional oil and gas wells. States could elect to prohibit hydraulic fracturing altogether, as was announced in December 2014 with regard to hydraulic fracturing activities in New York. Also, certain local governments have adopted, and additional local governments may further adopt, ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. Further, several federal governmental agencies are conducting reviews and studies on the environmental aspects of hydraulic fracturing, including the EPA. For example, in December 2016, the EPA issued its final report on a study it had conducted over several years regarding the effects of hydraulic fracturing on drinking water sources. The final report, contrary to several previously published draft reports issued by the EPA, found instances in which impacts to drinking water may occur. However, the report also noted significant data gaps that prevented the EPA from determining the extent or severity of these impacts. 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. In a few instances, operators of injection disposal wells in the vicinity of seismic events have been ordered to reduce injection volumes or suspend operations. Some state regulatory agencies, including those in Colorado, Ohio, Oklahoma and Texas, have modified their regulations to account for induced seismicity. While Pennsylvania is not one of the states where such
regulation has been enacted, regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and 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.
The adoption of new laws, regulations or ordinances at the federal, state or local levels imposing more stringent restrictions on hydraulic fracturing could make it more difficult for our customers to complete natural gas wells, increase our customers' costs of compliance and doing business, and otherwise adversely affect the hydraulic fracturing services they perform, which could negatively impact demand for our gathering, transmission and storage
, or water
services.
Furthermore, the tax laws, rules and regulations that affect our customers are subject to change. For example, Pennsylvania's governor and legislature have continued to discuss the imposition of a state severance tax on the extraction of natural resources, including natural gas produced from the Marcellus,
Utica and
Upper Devonian Shale formations, either in replacement of or in addition to the existing state impact fee. A consensus on the characteristics, such as the effective tax rate, or enactment of a state severance tax has yet to be reached. Any such increase or change could adversely impact the earnings, cash flows and financial position of our customers and cause them to reduce their drilling in the areas in which we operate.
Our exposure to direct commodity price risk may increase in the future.
For the years ended
December 31, 2018
and 2017, approximately
54%
and 84%, respectively, of EQM's revenues were generated from firm reservation fees under long-term contracts. The decrease from 2017 to 2018 reflects the inclusion of RMP's gathering systems for a full year compared to the period from November 13, 2017 through December 31, 2017, as RMP's gathering systems were not supported by contracts with firm reservation fee components. Rather, all of RMP's gathering revenues were generated under long-term interruptible service contracts. As a result, following the EQM-RMP Merger, we have greater exposure to short- and medium-term declines in volumes of gas produced and gathered on our systems than we have historically. Although we intend to
execute
long-term firm contracts with new customers in the future, our efforts to obtain such contractual terms may not be successful. Our water service agreements are volumetric in nature and therefore may be more sensitive to fluctuations in commodity prices and downturns in production by our customers in the future. In addition, we may acquire or develop additional midstream assets in the future that do not provide services primarily based on capacity reservation charges or other fixed fee arrangements and therefore have a greater exposure to fluctuations in commodity price risk than our current operations. Future exposure to the volatility of natural gas prices, including regional basis differentials, as a result of our future contracts could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt 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, if such rights-of-way lapse or terminate or if our facilities are not properly located within the boundaries of such rights-of-way. Although many of these rights are perpetual in nature, we occasionally
obtain
the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. If we were to be unsuccessful in negotiating or renegotiating rights-of-way, we might have to institute condemnation proceedings on our FERC-regulated assets or relocate our facilities for non-regulated assets. A loss of rights-of-way or a relocation could have a material adverse effect on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders. Additionally, even when we own an interest in the land on which our pipelines and facilities have been constructed, agreements with correlative rights owners may require us to relocate pipelines and facilities, shut in storage facilities to facilitate the development of the correlative rights owners' estate, or pay the correlative rights owners the lost value of their estate if they are not willing to accommodate development.
Any significant and prolonged change in or stabilization of natural gas prices could have a negative impact on our natural gas storage business.
Historically, natural gas prices have been seasonal and volatile, which has enhanced demand for and increased the value of our storage services. The natural gas storage business has benefited from significant short-term price fluctuations and seasonal price sensitivity, which impacts the level of demand for our services and the rates we are able to charge for such services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. However, the market for natural gas may not continue to experience short-term volatility and seasonal price sensitivity in the future at the levels previously seen. If price volatility and seasonality in the natural gas industry decrease, because of
increased production volumes and higher demand for natural gas during the injection season, the demand for our storage services and the prices that we will be able to charge for those services may decline.
In addition to volatility and seasonality, an extended period of high natural gas prices would increase the cost of acquiring base gas and drilling new storage wells due to higher demand for drilling rigs and likely place upward pressure on the costs of associated storage expansion activities. An extended period of low natural gas prices could adversely impact storage values for some period of time until market conditions adjust. These commodity price impacts could have a negative impact on our business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
We have entered into joint
ventures
, and may in the future enter into additional or modify existing joint ventures, that might restrict our operational and corporate flexibility. In addition, these joint ventures are subject to many of the same operational risks to which we are subject.
We have entered into joint
ventures
to construct the MVP
and MVP Southgate projects
and may in the future enter into additional joint venture arrangements with third parties. Joint venture arrangements may restrict our operational and corporate flexibility. Because we do not control all of the decisions of the MVP Joint Venture, it may be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our or the joint venture's best interests. For example, we cannot unilaterally cause the distribution of cash by the MVP Joint Venture. Moreover, joint venture arrangements involve various risks and uncertainties, such as committing us to fund operating and/or capital expenditures, the timing and amount of which we may not control, and our joint venture partners may not satisfy their financial obligations to the joint venture.
In addition, the operations of the MVP Joint Venture and any joint ventures we may enter into in the future are subject to many of the same operational risks to which we are subject
to.
Our significant indebtedness, and any future indebtedness, as well as restrictions under our debt agreements, could adversely affect our
operating flexibility,
business, financial condition, results of operations, liquidity and ability to make quarterly cash distributions to our unitholders.
Our debt agreements contain various covenants and restrictive provisions that limit our ability to, among other things:
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incur or guarantee additional debt;
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make distributions on or redeem or repurchase units;
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incur or permit liens on assets;
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enter into certain types of transactions with affiliates;
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enter into certain mergers or acquisitions; and
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dispose of all or substantially all of our assets.
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In
October 2018, we
amended and restated our credit facility to increase the borrowing capacity from $
1 billion
to $
3
billion and extend the term to
October 2023. Our
credit facility contains a covenant requiring us to maintain a consolidated leverage ratio of not more than 5.00 to 1.00 (or not more than 5.50 to 1.00 for certain measurement periods following the consummation of certain acquisitions). Our ability to meet these covenants can be affected by events beyond our control and we cannot assure our unitholders that we will meet these covenants. In addition, our $
3
billion credit facility contains events of default customary for such facilities, including the occurrence of a change of control.
Furthermore, in June 2018, we issued senior unsecured notes in an aggregate principal amount of $2.5 billion, consisting of $1.1 billion in aggregate principal amount of its 4.75% senior notes due 2023, $850 million in aggregate principal amount of its 5.50% senior notes due 2028, and $550 million in aggregate principal amount of its 6.50% senior notes due 2048.
The provisions of our debt agreements may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our debt agreements could result in an event of default, which could enable our creditors to, subject to the terms and conditions of the applicable agreement, declare any outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. 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. Our credit facility also has cross default provisions that apply to any other indebtedness we may have with an aggregate principal amount in excess of $25 million.
We may in the future incur additional debt. Our level of debt could have important consequences to us, including the following:
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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes, may be impaired or such financing may not be available on favorable terms;
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our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make interest payments on our debt;
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we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
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our flexibility in responding to changing business and economic conditions may be limited.
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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, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our current or future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may not be able to effect any of these actions on satisfactory terms or at all.
Our substantial indebtedness and the additional debt we will incur in the future for, among other things, working capital, capital expenditures, capital contributions to the MVP Joint Venture, acquisitions or operating activities may adversely affect our liquidity and therefore our ability to make quarterly cash distributions to our unitholders.
In addition, our significant indebtedness may be viewed negatively by credit rating agencies, which could result in increased costs for us to access the capital markets. Any future downgrade of the debt issued by us or our subsidiaries could significantly increase our capital costs or adversely affect our ability to raise capital in the future.
The credit and risk profile of Equitrans Midstream could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
The credit and business risk profiles of our ultimate parent Equitrans Midstream may be factors considered in credit evaluations of us. This is because our general partner, which is controlled by Equitrans Midstream through Equitrans Midstream's ownership interest of our general partner, controls our business activities, including our cash distribution policy and growth strategy. Due to our relationship with Equitrans Midstream, our ability to access the capital markets, or the pricing or other terms of any capital markets transactions, may be adversely affected by any impairments to Equitrans Midstream's financial condition, including the degree of its financial leverage and its dependence on cash flows from our general partner to service its indebtedness, or adverse changes in its credit ratings. Any material limitations on our ability to access capital as a result of adverse changes at Equitrans Midstream could limit our ability to obtain future financing under favorable terms, or at all, or could result in increased financing costs in the future. Similarly, material adverse changes at Equitrans Midstream could negatively impact our unit price, limiting our ability to raise capital through equity issuances or debt financing, could negatively affect our ability to engage in, expand or pursue our business activities, and could also prevent us from engaging in certain transactions that might otherwise be considered beneficial to us.
A downgrade of our credit ratings, which are determined by independent third parties, could impact our liquidity, our access to capital, and our costs of doing business.
If any credit rating agency downgrades our credit ratings, our access to credit markets may be limited, our borrowing costs could increase, and we may be required to provide additional credit assurances in support of commercial agreements, such as joint venture agreements and construction contracts, the amount of which may be substantial. Our credit ratings by Moody's Investors Service (Moody's), Standard & Poor's Ratings Service (S&P) and Fitch Ratings Service (Fitch) were Ba1, BBB- and BBB-, respectively, as of February 14, 2019. In order to be considered investment grade, we must be rated Baa3 or higher by Moody's, BBB- or higher by S&P and BBB- or higher by Fitch. Our non-investment grade credit rating by Moody's and any future downgrade of our S&P and/or Fitch credit ratings to non-investment grade may result in greater borrowing costs and collateral requirements than would be available to us if all our credit ratings were investment grade. Our ability to access capital markets could also be limited by economic, market or other disruptions. An increase in the level of our indebtedness in the future may result in a downgrade in the ratings that are assigned to our debt. See "
The credit and risk profile of Equitrans Midstream could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital
" in the above section. Credit rating agencies perform an independent analysis when assigning credit ratings. This analysis includes a number of criteria such as business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are subject to revision or withdrawal at any time by the ratings agencies.
Increases in interest rates could adversely impact demand for our storage capacity, our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make quarterly cash distributions at our intended levels.
There is a financing cost for our customers to store natural gas in our storage facilities. That financing cost is impacted by the cost of capital or interest rates incurred by the customer in addition to the commodity cost of the natural gas in inventory. Absent other factors, a higher financing cost adversely impacts the economics of storing natural gas for future sale. As a result, a significant increase in interest rates could adversely affect the demand for our storage capacity independent of other market factors.
In addition, interest rates on our current credit facility, future credit facilities and debt securities could be higher than current levels, causing our financing costs to increase. 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 units, and a rising interest rate environment could have an adverse impact on our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make quarterly cash distributions at our intended levels.
Risks Inherent in an Investment in Us
Equitrans Midstream controls our general partner, which has sole responsibility for conducting our business and managing our operations. Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner has limited its state law fiduciary duties to us and our unitholders, which may permit it to favor its own interests to the detriment of us and our unitholders. Additionally, the duties of our general partner's officers and directors may conflict with their duties as officers and/or directors of Equitrans Midstream.
Equitrans Midstream’s only cash-generating assets are its partnership interests in us. Through its ownership and control of our general partner, Equitrans Midstream has the power to appoint all of the officers and directors of our general partner. Conflicts of interest will arise among Equitrans Midstream 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 Equitrans Midstream over our interests and the interests of our unitholders. These conflicts include the following situations, among others:
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Neither our partnership agreement nor any other agreement requires Equitrans Midstream to pursue a business strategy that favors us, and the directors and officers of Equitrans Midstream have a fiduciary duty to make these decisions in the best interests of Equitrans Midstream, which may be contrary to our interests. Equitrans Midstream may choose to shift the focus of its investment and growth to areas not served by our assets.
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Equitrans Midstream is not limited in its ability to compete with us and may offer business opportunities and/or sell midstream assets to third parties without first offering us the right to bid for them.
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Our general partner is allowed to take into account the interests of parties other than us, such as Equitrans Midstream, in resolving conflicts of interest, which has the effect of limiting its state law fiduciary duty to our unitholders.
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Our general partner determines whether or not we incur debt and that decision may affect our credit ratings.
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Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limits our general partner's liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty under state law.
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Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.
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Our general partner controls the enforcement of the obligations that it and its affiliates owe to us, including Equitrans Midstream's obligations under the ETRN Omnibus Agreement.
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Our partnership agreement gives our general partner broad discretion in establishing financial reserves for the proper conduct of our business. These reserves will affect the amount of cash available for distribution to our unitholders.
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Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash available for distribution to our unitholders.
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Our general partner determines the amount and timing of any capital expenditures and, in accordance with the terms of our partnership agreement, whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion or investment capital expenditure, which does not reduce operating surplus. These determinations can affect the amount of cash that is distributed to our unitholders.
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Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.
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Our general partner may cause us to borrow funds in order to permit the payment of cash distributions.
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Our partnership agreement permits us to classify up to $30 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus.
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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.
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Our general partner intends to limit its liability regarding our contractual and other obligations.
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Our general partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if they own more than 80% of the common units.
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Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
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In addition, our general partner's officers and directors have duties to manage our business in a manner beneficial to us, our unitholders and the owner of our general partner that is controlled by Equitrans Midstream. However, five of our general partner's directors and all of its officers are also officers and/or directors of Equitrans Midstream and owe fiduciary duties to Equitrans Midstream. Consequently, these directors and officers may encounter situations in which their obligations to Equitrans Midstream, on the one hand, and us, on the other hand, are in conflict. The resolution of these conflicts may not always be in our best interest or that of our unitholders.
Further, our general partner's officers, all of whom are also officers of Equitrans Midstream (and are compensated by Equitrans Midstream), will have responsibility for overseeing the allocation of their own time and time spent by administrative personnel on our behalf and on behalf of Equitrans Midstream. These officers face conflicts regarding these time allocations that may adversely affect our results of operations, cash flows and financial condition.
Please read Item 13, "Certain Relationships and Related Transactions, and Director Independence" in this Annual Report on Form 10-K.
Equitrans Midstream may compete with us, which could adversely affect our ability to grow and our results of operations and cash available for distribution.
Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Affiliates of our general partner, including Equitrans Midstream and its other subsidiaries, are not prohibited from owning assets or engaging in businesses that compete directly or indirectly with us. Equitrans Midstream currently holds interests in entities that own a significant amount of natural gas midstream assets and may make investments in and purchases of entities that acquire, own and operate other natural gas midstream assets. Equitrans Midstream is under no obligation to make any acquisition opportunities available to us. Moreover, while Equitrans Midstream may offer us the opportunity to buy additional assets from it, it is under no contractual obligation to accept any offer we might make with respect to such opportunity.
Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Equitrans Midstream. 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 common unitholders.
Our general partner may require us to forgo certain transactions in order to avoid the risk of Equitrans Midstream incurring material tax-related liabilities or indemnification obligations under Equitrans Midstream's tax matters agreement with EQT.
In order for Equitrans Midstream to avoid incurring material tax-related liabilities or indemnification obligations under its tax matters agreement with EQT, entered into in connection with the Separation, our general partner may require us to forgo certain transactions that would otherwise be advantageous, for the two-year period following the Separation. In particular, our general partner may require us to continue to operate certain business operations, even if a sale or discontinuance of such business would otherwise be advantageous. Moreover, to preserve the tax-free treatment of the Separation, our general partner may require us to forgo certain transactions, including certain asset dispositions and other strategic transactions.
Equitrans Midstream or EQT may fail to perform under various transaction agreements that were executed as part of the Separation, or Equitrans Midstream may fail to have necessary systems and services in place when certain of the transaction agreements expire.
In connection with the Separation, Equitrans Midstream and EQT entered into a Separation and Distribution Agreement as well as various other agreements, including a transition services agreement. The transition services agreement provides for the performance of select services by each company for the benefit of the other, in each case for a limited period of time after the Separation. With respect to services to be performed by EQT for the benefit of us, we are relying on EQT to satisfy its performance obligations under these agreements. If EQT is unable or unwilling to satisfy its obligations under these agreements, including its indemnification obligations, our business, results of operations and financial condition could be materially and adversely affected. If Equitrans Midstream does not have in place its own systems and services, or if Equitrans Midstream does not have agreements with other providers of these services, once transaction agreements with EQT expire or terminate, we may not be able to operate our business effectively and our profitability may decline. Equitrans Midstream is in the process of creating its own, or engaging third parties to provide, systems and services to replace many of the systems and services that EQT provided to us. However, Equitrans Midstream may not be successful in implementing these systems and services, we may incur additional costs in connection with or following the implementation of these systems and services, and Equitrans Midstream may not be successful in transitioning data from EQT's systems to its own. For a description of these agreements with EQT, see "Item 13. Certain Relationships and Related Party Transactions and Director Independence."
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.
We expect that we will distribute all of our available cash to our unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because we intend to distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement, and we do not anticipate there being limitations in our credit facilities, on our ability to issue additional units, including units ranking senior to our common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which in turn may impact the available cash that we have to distribute to our unitholders.
The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.
Unlike most corporations, we are not required by NYSE rules to have, and we do not intend to have, a majority of independent directors on our general partner's board of directors or a compensation committee 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 NYSE's shareholder approval rules. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.
If any of our unitholders are not eligible taxable holders, such unitholders will not be entitled to allocations of income or loss or distributions or voting rights on their common units and their common units will be subject to redemption.
In order to avoid any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or an analogous regulatory body, we have adopted certain requirements regarding those investors who may own our common units. Eligible taxable holders are defined in our partnership agreement and generally include any individual or entity (i) whose, or whose owners', U.S. federal income tax status (or lack of proof thereof) does not have or is not reasonably likely to have, as determined by our general partner, a material adverse effect on the rates that can be charged to customers with respect to assets that are subject to regulation by the FERC or similar
regulatory body; or (ii) as to whom our general partner cannot make the determination in clause (i) above, if our general partner determines that it is in our best interest to permit such individual or entity to own our partnership interests. If any of our unitholders fails to fit the requirements of an eligible taxable holder or fails to certify or has falsely certified that such holder is an eligible taxable holder, such unitholder will not receive allocations of income or loss or distributions or voting rights on their units and they run the risk of having their units redeemed by us at the market price calculated in accordance with our partnership agreement as of the date of redemption. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.
Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replace those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the partners where the language in the partnership agreement does not provide for a clear course of action. This provision 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:
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how to allocate corporate opportunities among us and other affiliates;
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whether to exercise its limited call right;
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whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;
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how to exercise its voting rights with respect to the units it owns; and
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whether or not to consent to any merger, consolidation or conversion of the partnership or amendment to our partnership agreement.
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By purchasing a common unit, a common unitholder agrees to become bound by the provisions in our partnership agreement, including the above provisions.
Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:
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whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner and any committee thereof (including the conflicts committee), as applicable, 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 the best interests of our partnership, and, except as specifically provided by our partnership agreement, 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;
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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;
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our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
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our general partner will not be in breach of its obligations under our partnership agreement (including any duties to us or our unitholders) if a transaction with an affiliate or the resolution of a conflict of interest is:
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approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;
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approved by the vote of unitholders holding a majority of our outstanding common units, excluding any common units owned by our general partner and its affiliates;
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determined by the board of directors of our general partner to be on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or
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determined by the board of directors of our general partner to be 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.
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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 of our general partner 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 third and fourth sub-bullets 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 challenging such determination, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.
Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce
distributable cash flow
to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.
Prior to making any distribution to our common unitholders, we will reimburse our general partner and its affiliates, including Equitrans Midstream, for expenses they incur and payments they make on our behalf. Under our partnership agreement and the ETRN Omnibus Agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including administrative costs, such as compensation expenses for those persons who provide services necessary to run our business, and insurance expenses. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.
Our unitholders do not elect our general partner or vote on our general partner's directors.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights and, therefore, limited ability to influence management's decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. Rather, the board of directors of our general partner will be appointed by Equitrans Midstream. Furthermore, if our public unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.
Our unitholders' voting rights are restricted by a provision in our partnership agreement which provides that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of our unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management. As a result, the price at which our common units will trade may be lower because of the absence or reduction of a takeover premium in the trading price.
Our general partner may transfer its general partner interest, or the control of our general partner may be transferred, to a third party without unitholder consent.
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 our unitholders. Furthermore, our partnership agreement does not restrict the ability of (i) EQGP to transfer all or a portion of its ownership interest in our general partner to a third party, or (ii) Equitrans Midstream to transfer all or a portion of its ownership interest in EQGP's general partner to a third party. The new owner of our general partner or EQGP's general partner, as the case may be, would then be in a position to replace the board of directors and officers
of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers of our general partner.
We may issue additional units without unitholder approval, which would dilute our unitholders' existing ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests, including limited partner interests that rank senior to our common units, that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:
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our existing unitholders' proportionate ownership interest in us will decrease;
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the amount of distributable cash flow on each unit may decrease;
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the ratio of taxable income to distributions may increase;
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the relative voting strength of each previously outstanding unit may be diminished; and
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the market price of our common units may decline.
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Equitrans Midstream may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of our common un
its.
As of February 14, 2019, Equitrans Midstream beneficially owned 37,245,455 of our common units, representing a 30.6% limited partner interest in us. Following the completion of the EQM IDR Transaction, we expect Equitrans Midstream to own 117,245,455 of our common units and 7,000,000 of our Class B units, representing a 59.9% limited partner interest in us. In addition, we have agreed to provide our general partner and its affiliates, including Equitrans Midstream, with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of our common units or on any trading market that may develop.
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 permits our general partner to limit its liability, 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.
Our general partner has a call right that may require our unitholders to sell their common 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 remaining units held by unaffiliated persons at a price that is not less than the then-current market price of our common units. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Our common unitholders may also incur a tax liability upon a sale of their common units. As of February 14, 2019, affiliates of our general partner owned a 30.6% limited partner interest in us. Following the completion of the EQM IDR Transaction, we expect those affiliates to own 59.9% of our outstanding common units, which we expect to consist of 117,245,455 common units and 7,000,000 Class B units.
Our unitholders' 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. A unitholder could be liable for any and all of our obligations as if that unitholder were a general partner if a court or government agency were to determine that:
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we were conducting business in a state but had not complied with that particular state's partnership statute; or
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such unitholder'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 constitutes "control" of our business.
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Furthermore, under Delaware law, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution under certain circumstances.
Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders.
Our general partner may mortgage, pledge or grant a security interest in all or substantially all of our assets without prior approval of our unitholders. If our general partner at any time were to decide to incur debt and secure its obligations or indebtedness by all or substantially all of our assets, and if our general partner were to be unable to satisfy such obligations or repay such indebtedness, the lenders could seek to foreclose on our assets. The lenders could also sell all or substantially all of our assets under such foreclosure or other realization upon those encumbrances without prior approval of our unitholders, which would adversely affect the price of our common units.
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 Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of 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. Transferees of common units are liable both for the obligations of the transferor to make contributions to the partnership that were known to the transferee at the time of transfer 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.
Tax Risks to Our Common Unitholders
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
distributable cash flow
to our unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not currently plan to request, a ruling from the IRS with respect to our treatment 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 21.0%, 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 distributable cash flow to our unitholders would be substantially reduced. Therefore, if we were treated as a corporation for federal income tax purposes there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
If we were subjected to a material amount of additional entity-level taxation by individual states or other taxing jurisdictions, it would reduce our distributable cash flow to our unitholders.
Changes in current law may subject us to additional entity-level taxation by individual states or other taxing jurisdictions. Because of widespread budget deficits and other reasons, several states and other taxing jurisdictions are evaluating ways to subject partnerships to entity-level taxation through the imposition of income, franchise and other forms of taxation. Imposition
of such additional tax on us would reduce the distributable cash flow to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the proposals could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals 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 common 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 such unitholder, 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 recently enacted law known as the Tax Cuts and Jobs Act of 2017 (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 our 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 our common units.
If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our
distributable cash flow
to our unitholders.
We have not requested, and do not currently plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other tax matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in a prospectus or from the positions we take. 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 impact on the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our distributable cash flow.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may assess and collect any resulting taxes (including any applicable penalties and interest) 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 might be substantially reduced.
Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it (and some states) may assess and collect any resulting taxes (including any applicable interest and penalties) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or 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 might 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.
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, for taxable years beginning after December 31, 2017, our deduction for "business interest" 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 common units could be more or less than expected.
If our unitholders sell their common units, our unitholders will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of our unitholders' allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price our unitholders receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale or other disposition of our unitholders' common 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 our unitholders' share of our nonrecourse liabilities, if our unitholders sell their common units, our unitholders may incur a tax liability in excess of the amount of cash they receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. 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 common 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 Department of the Treasury and the IRS have determined that this withholding requirement should not
apply to any disposition of a publicly traded interest in a publicly traded partnership (such as us) until regulations or other guidance have been issued clarifying the application of this withholding requirement to dispositions of interests in publicly traded partnerships. Accordingly, while this new withholding requirement does not currently apply to interests in us, there can be no assurance that such requirement will not apply in the future.
Tax-exempt entities and non-U.S. persons should consult a tax advisor before investing in our common units.
We will treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from our unitholders' sales of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders' tax returns.
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 convention, but such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.
A unitholder who disposes of units prior to the ex-dividend date immediately preceding the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition (and any prior month for which the holder held such units on the first day of such month) but will not be entitled to receive a cash distribution for that period.
A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned common units, the unitholder may no longer be treated for federal income tax purposes as a partner with respect to those common 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 common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Our 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 common units.
We have adopted certain valuation methodologies in determining a unitholder's allocations of income, gain, loss and deduction. The IRS may challenge these methodologies or the resulting allocations, and such a challenge could adversely affect the value of our common units.
In determining the items of income, gain, loss and deduction allocable to our unitholders, we must routinely 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 common 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 timing or amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders' sale of common units and
could have a negative impact on the value of the common units or result in audit adjustments to our unitholders' tax returns without the benefit of additional deductions.
As a result of investing in our common units, our unitholders may become 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 own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We own property or conduct business in Pennsylvania, West Virginia and Ohio and will be expanding into Virginia with the MVP project and North Carolina with the MVP Southgate project, each of which currently imposes a personal income tax on individuals. Each of these states also imposes an income or gross receipts tax on corporations and other entities. As we make acquisitions or expand our business, we may own property or conduct business in additional states that impose a personal income tax. It is our unitholders' responsibility to file all U.S. federal, state and local tax returns.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax laws and regulations, including federal, state and foreign 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.
See also Item 7A, "Quantitative and Qualitative Disclosures About Market Risk," for further discussion regarding EQM's exposure to market risks, which is incorporated herein by reference.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Equitrans Midstream leases its headquarters office in Pittsburgh, Pennsylvania and its corporate office in Canonsburg, Pennsylvania. Pursuant to the ETRN Omnibus Agreement, EQM pays a proportionate share of Equitrans Midstream's costs to lease the building.
EQM's real property falls into two categories: (i) parcels that it owns in fee and (ii) parcels in which its interest derives from leases, easements, rights-of-way, permits or licenses from landowners or governmental authorities permitting the use of such land for EQM's operations. Certain lands on which EQM's pipelines and facilities are located are owned by EQM in fee title, and EQM believes that it has satisfactory title to these lands. The remainder of the lands on which EQM's pipelines and facilities are located are held by EQM pursuant to surface leases or easements between EQM, as lessee or grantee, and the respective fee owners of the lands, as lessors or grantors. EQM has held, leased or owned many of these lands for many years without any material challenge known to EQM relating to the title to the land upon which the assets are located, and EQM believes that it has satisfactory leasehold estates, easement interests or fee ownership to such lands. EQM believes that it has satisfactory title to all of its material leases, easements, rights-of-way, permits and licenses, and EQM has no knowledge of any material challenge to its title to such assets or their underlying fee title.
There are, however, certain lands within EQM's storage pools as to which it may not currently have vested real property rights, some of which are subject to ongoing acquisition negotiations or condemnation proceedings. In accordance with EQM's FERC certificates, the geological formations within which its permitted storage facilities are located cannot be used by third parties in any way that would detrimentally affect its storage operations, and EQM has the power of eminent domain with respect to the acquisition of necessary real property rights to use such storage facilities. Certain property owners have initiated legal proceedings against EQM and its affiliates for trespass, inverse condemnation and other claims related to these matters, and there is no assurance that other property owners will not initiate similar legal proceedings against EQM and its affiliates prior to final resolution.
See "Item 1. Business" for a discussion and map of EQM's operations.