Form 10-K RATTLER MIDSTREAM LP For: Dec 31

February 25, 2021 4:46 PM EST

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rtlr-20201231
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT UNDER SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2020
OR
TRANSITION REPORT UNDER SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-38919
Rattler Midstream LP
(Exact Name of Registrant As Specified in Its Charter)
DE
83-1404608
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification Number)
500 West Texas
Suite 1200
Midland,TX
79701
(Address of principal executive offices)
(Zip code)
(432) 221-7400
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common UnitsRTLRThe Nasdaq Stock Market LLC
(NASDAQ Global Select Market)
Securities registered pursuant to section 12(g) of the Act:
None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes      No   
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes      No   
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes       No   
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).   Yes       No   
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large Accelerated FilerAccelerated Filer
Non-Accelerated FilerSmaller Reporting Company
Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes      No   
The aggregate market value of the common units held by non-affiliates was approximately $423.6 million on June 30, 2020, the last business day of the registrant’s most recently completed second fiscal quarter, based on closing prices in the daily composite list for transactions on the Nasdaq Global Select Market on such date. As of February 19, 2021, 41,612,027 common units representing limited partner interests and 107,815,152 Class B units representing limited partner interests were outstanding.
Documents Incorporated By Reference: None



RATTLER MIDSTREAM LP
FORM 10-K
FOR THE YEAR ENDED DECEMBER 31, 2020
TABLE OF CONTENTS
Page
S-1



GLOSSARY OF OIL AND NATURAL GAS TERMS
The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K (this “Annual Report” or this “report”):
Basin
A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel
One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil, natural gas liquids or other liquid hydrocarbons.
Bbl/d
Bbl per day.
Boe
Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
Boe/d
Boe per day.
British thermal unit or Btu
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Completion
The process of treating a drilled well, followed by the installation of permanent equipment for the production of natural gas or oil or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.
Condensate
Liquid hydrocarbons associated with production that is primarily natural gas.
Crude oil
Liquid hydrocarbons found in the earth, which may be refined into fuel sources.
Dry hole
A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
Field
The general area encompassed by one or more crude oil or natural gas reservoirs or pools that are located on a single geologic feature, or that are otherwise closely related to such geologic feature (either structural or stratigraphic).
Gross acres or gross wells
The total acres or wells, as the case may be, in which a working interest is owned.
Horizontal drilling
A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.
Hydraulic fracturing
The process of creating and preserving a fracture or system of fractures in a reservoir rock, typically by injecting a fluid under pressure through a wellbore and into the targeted formation.
Hydrocarbon
An organic compound containing only carbon and hydrogen.
MBbl
One thousand barrels.
MBbl/d
One thousand barrels per day.
MBoe
One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
MBoe/d
One thousand barrels of crude oil equivalent per day.
Mcf
One thousand cubic feet of natural gas.
Mcf/d
One thousand cubic feet of natural gas per day.
MMBbl
One million barrels.
MMBbl/d
One million barrels per day.
MMBtu
One million British thermal units.
MMBtu/d
One million British thermal units per day.
Natural gas
Hydrocarbon gas found in the earth, composed of methane, ethane, butane, propane and other gases.
NGL
Natural gas liquids; the combination of ethane, propane, butane and natural gasolines that, when removed from natural gas, becomes liquid under various levels of higher pressure and lower temperature.
Operator
The individual or company responsible for the exploration and/or production of a crude oil or natural gas well or lease.
Plugging and abandonment
Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
ii

Reserves
Estimated remaining quantities of crude oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering crude oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., potentially recoverable resources from undiscovered accumulations).
Throughput
The volume of product transported or passing through a pipeline, plant, terminal or other facility.
Tight formation
A formation with low permeability that produces natural gas with very low flow rates for long periods of time.
Working interest
An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.


iii

GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms used in this report:
Delaware Act
Delaware Revised Uniform Limited Partnership Act.
Diamondback
Diamondback Energy, Inc., a Delaware corporation, and its subsidiaries other than the Partnership and its subsidiaries (including the Operating Company).
DOT
The U.S. Department of Transportation.
EPA
U.S. Environmental Protection Agency.
Exchange Act
The Securities Exchange Act of 1934, as amended.
FERC
Federal Energy Regulatory Commission.
GAAP
Accounting principles generally accepted in the United States.
General partner
Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly owned subsidiary of Diamondback.
GHG
Greenhouse gases.
IPO
The Partnership’s initial public offering.
IRS
Internal Revenue Service.
JOBS Act
The Jumpstart Our Business Startups Act of 2012.
Nasdaq
The Nasdaq Global Select Market.
NotesThe $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 issued on July 14, 2020.
Operating Company or OpCo
Rattler Midstream Operating LLC, a Delaware limited liability company and a consolidated subsidiary of the Partnership.
OSHA
Federal Occupational Safety and Health Act.
Partnership
Rattler Midstream LP, a Delaware limited partnership.
Partnership agreement
The first amended and restated agreement of limited partnership of Rattler Midstream LP, dated May 28, 2019.
Predecessor
The Operating Company, prior to May 28, 2019 for accounting purposes.
SEC
Securities and Exchange Commission.
Securities Act
The Securities Act of 1933, as amended.

iv

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Various statements contained in this Annual Report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. These forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond our control. All statements, other than statements of historical fact, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “continue,” “predict,” “potential,” “project,” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.

Factors that could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements include the factors discussed in this Annual Report, such as those detailed under “Item 1A. Risk Factors,” as well as the following factors:

Diamondback’s ability to meet its drilling and development plans on a timely basis or at all;
the volatility of realized oil and natural gas prices, including in Diamondback’s area of operation in the Permian Basin, and the extent and duration of price reductions and increased production by the Organization of the Petroleum Exporting Countries, or OPEC, members and other oil exporting nations;
the threat, occurrence, potential duration or other implications of epidemic or pandemic diseases, including the ongoing COVID-19 pandemic, or any government responses to such threat, occurrence or pandemic;
logistical challenges and supply chain disruptions during the ongoing COVID-19 pandemic;
changes in general economic, business or industry conditions;
conditions in the capital, financial and credit markets;
competitive conditions in our industry and the effect of U.S. energy, monetary and trade policies;
U.S. and global economic conditions and political and economic developments, including the effects of the recent U.S. presidential and congressional elections on energy and environmental policies;
actions taken by third party operators, gatherers, processors and transporters;
the demand for and costs of conducting midstream infrastructure services;
our ability to successfully implement our business plan;
our ability to complete internal growth projects on time and on budget;
our ability to identify, complete and effectively integrate acquisitions into our operations;
our ability to achieve anticipated synergies, system optionality and accretion associated with acquisitions;
the impact of potential impairment charges;
the results of our investments in joint ventures;
the availability and price of crude oil and natural gas to the consumer compared to the price of alternative and competing fuels;
competition from the same and alternative energy sources;
energy efficiency and technology trends;
operating hazards and other risks incidental to our midstream services;
natural disasters, weather-related delays, casualty losses and other matters beyond our control;
impact of severe weather conditions, including the recent winter storms in the Permian Basin, on production volumes on our mineral and royalty acreage;
defaults by Diamondback under our commercial agreements;
our lack of asset and geographic diversification;
increases in our tax liability;
v

the effect of existing and future laws and government regulations;
civil unrest, terrorist attacks or cyber threats;
the effects of future litigation; and
certain other factors discussed elsewhere in this report.

All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by securities laws. You should not place undue reliance on these forward-looking statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied in the forward-looking statements.

vi

PART I
References in this Annual Report to “the Predecessor,” “our Predecessor,” “we,” “our,” “us” or like terms when used for periods prior to May 28, 2019 refer to Rattler Midstream Operating LLC, which Diamondback Energy, Inc. contributed to Rattler Midstream LP in connection with Rattler Midstream LP’s initial public offering of common units, which we refer to as our IPO, on May 28, 2019. When used for periods on and after May 28, 2019, references in this Annual Report to (i) “Rattler,” “the Partnership,” “our Partnership,” “we,” “our,” “us” or like terms refer to Rattler Midstream LP individually and collectively with its subsidiary, Rattler Midstream Operating LLC, as the context requires, (ii) “our general partner” refers to Rattler Midstream GP LLC, our general partner and a wholly owned subsidiary of Diamondback, (iii) the “Operating Company” or “OpCo” refer to Rattler Midstream Operating LLC, and (iv) “Diamondback” refers collectively to Diamondback Energy, Inc. and its subsidiaries other than the Partnership and its subsidiaries.

ITEMS 1 AND 2.     BUSINESS AND PROPERTIES

Overview

We are a Delaware limited partnership formed by Diamondback to own, operate, develop and acquire midstream and energy-related infrastructure assets in the Midland and Delaware Basins of the Permian Basin, one of the most prolific oil producing areas in the world. We have elected to be treated as a corporation for U.S. federal income tax purposes. Our operations are conducted through, and our operating assets are owned by, the Operating Company, in which we directly own a 28% controlling membership interest as of December 31, 2020. Our assets and operations are reported in two operating business segments: (i) midstream services and (ii) real estate operations.

We are Diamondback’s primary provider of crude oil, natural gas and water-related midstream services (including water sourcing and transportation and produced water gathering and disposal). We have long-term acreage dedications, which we refer to as the Acreage Dedications, from Diamondback spanning approximately 395,000 gross acres on Diamondback’s core leasehold in the Permian (approximately 210,000 gross acres in the Midland Basin and approximately 185,000 gross acres in the Delaware Basin). In this Annual Report, we refer to the acreage subject to the Acreage Dedications as the Dedicated Acreage. We entered into commercial agreements with Diamondback in June 2018, effective as of January 1, 2018, that have initial terms ending in 2034.

Additionally, we own equity interests in three long-haul crude oil pipelines that run from the Permian to the Texas Gulf Coast. We also own equity interests in third-party operated gathering systems and processing facilities supported by commercial agreements, including acreage dedications with Diamondback and other operators. We are critical to Diamondback’s development plans because we provide long-term midstream solutions to its crude oil, natural gas and water-related needs.

Our general partner’s management team consists of members of the management team of Diamondback. We believe that our relationship with Diamondback and our common strategic and operational interests provide the optimal platform to execute our business plan and drive unitholder value.

Our Assets

As of December 31, 2020, we own and operate 927 miles of crude oil, natural gas, sourced water and produced water gathering pipelines on acreage that overlays Diamondback’s core Midland and Delaware Basin development areas. Our water system obtains and distributes sourced water for use in drilling and completion operations and collects flowback and produced water, which we refer to collectively as produced water, for recycling and disposal. Our oil and gas gathering systems transport oil and gas from the infield production batteries to intermediary pipelines. In addition to our gathering, distribution and disposal assets, we also own equity interests in three long-haul crude oil pipelines, an additional oil gathering system and an additional gas gathering and processing system.

The transportation of water and hydrocarbon volumes away from the producing wellhead is paramount to ensuring the efficient operations of a crude oil or natural gas well. To facilitate this transportation, our midstream infrastructure was built to include a network of gathering pipelines that collect and transport crude oil, natural gas, sourced water and produced water from Diamondback’s operations in the Midland and Delaware Basins. These assets are predominately located in Pecos, Reeves, Ward, Loving, Midland, Howard, Andrews, Martin and Glasscock Counties.

1

The following table provides information regarding our gathering, compression and transportation system as of December 31, 2020:
Pipeline Infrastructure Assets
(miles)(1)
Delaware Basin Midland Basin Permian Total
Crude oil108 46 154 
Natural gas155 — 155 
Produced water269 248 517 
Sourced water27 74 101 
Total559 368 927 
(capacity/capability)(1)
Delaware Basin Midland Basin Permian Total Utilization
Crude oil gathering (Bbl/d)210,000 65,000 275,000 36 %
Natural gas compression (Mcf/d)151,000 — 151,000 60 %
Natural gas gathering (Mcf/d)170,000 — 170,000 54 %
Produced water gathering and disposal (Bbl/d)1,310,000 1,810,000 3,120,000 26 %
Sourced water gathering (Bbl/d)120,000 455,000 575,000 44 %
(1)Does not include any assets of the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

Throughput

The following table provides information regarding our throughput volumes for each of the periods indicated:
Year Ended December 31,
(throughput)(1)
202020192018
Crude oil gathering (Bbl/d)92,056 85,164 47,338 
Natural gas gathering (MMBtu/d)121,637 85,283 39,252 
Produced water gathering and disposal (Bbl/d)821,543 806,078 281,916 
Sourced water gathering (Bbl/d)253,907 415,939 252,118 
(1)Does not include any volumes from the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

Crude oil and natural gas gathering and transportation assets

As of December 31, 2020, excluding the assets of our joint ventures discussed below, our crude oil and natural gas gathering system covers approximately 309 miles, consisting of (i) 154 miles of crude oil pipelines, which have 275,000 Bbl/d of crude oil throughput capacity and 118,000 Bbl of crude oil storage, and (ii) 155 miles of natural gas pipelines, which have 170,000 Mcf/d of natural gas gathering capacity and 151,000 Mcf/d of natural gas compression capability. Our crude oil and natural gas gathering and transportation system is purpose built with firm capacity on intermediary pipelines providing connections to long-haul pipelines that terminate on the Texas Gulf Coast. Our crude oil and natural gas gathered volumes, excluding volumes gathered by our joint ventures, averaged 112.0 MBoe/d for the year ended December 31, 2020.

Produced water gathering and disposal assets

Crude oil and natural gas cannot be produced without significant produced water transport and disposal capacity given the high water volumes produced alongside the hydrocarbons. At the well site, crude oil and produced water are separated to extract the crude oil for sale and the produced water for proper disposal and recycling. We own strategically located produced water gathering pipeline systems spanning a total of 517 miles that connect the overwhelming majority of Diamondback operated crude oil and natural gas wells to our produced water disposal well sites. As of December 31, 2020, we have a total of 135 produced water disposal wells with an aggregate capacity of 3.1 MMBbl/d located across the Midland and Delaware Basins. Diamondback has instituted a program in its operations to use treated water for completion operations, and 19% of the
2

sourced water volumes sold to Diamondback were recycled produced water during the year ended December 31, 2020. We have and expect to continue to realize increased margins for produced water disposal as a result of this recycling program.

Water sourcing and distribution assets

Our water sourcing and distribution system, with storage capacity of 58 MMBbl, is critical to Diamondback’s completion operations, and distributes water from sourced water wells from the Capitan Reef formation, Edwards-Trinity, Pecos Alluvium and Rustler aquifers in the Permian. Our sourced water system consists of a combination of permanent buried pipelines, portable surface pipelines and sourced water storage facilities, as well as pumping stations to transport the sourced water throughout the pipeline network. Having access to water sources is an important element of the hydraulic fracturing process in the Delaware Basin because modern completion methods require significantly more sourced water relative to the Midland Basin.

Investment in long-haul crude oil pipelines

We own a 10% equity interest in each of EPIC Crude Holdings LP and Gray Oak Pipeline, LLC, and a 4% equity interest in Wink to Webster Pipeline LLC. We refer to these joint ventures as the EPIC, Gray Oak and Wink to Webster joint ventures, respectively. Our equity interests in these pipeline joint ventures are expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation.

EPIC, which began full operations in April 2020, owns and operates a long-haul crude oil pipeline from the Permian and the Eagle Ford Shale to Corpus Christi, Texas. This pipeline, which we refer to as the EPIC pipeline, is capable of transporting approximately 600,000 Bbl/d which, with the installation of additional pumps and storage, can be increased to approximately 1,000,000 Bbl/d.

Gray Oak, which also began full operations in April 2020, owns and operates a long-haul crude oil pipeline from the Permian and the Eagle Ford Shale to points along the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas. This pipeline is capable of transporting approximately 900,000 Bbl/d.

Wink to Webster is a joint venture that is developing a long-haul crude oil pipeline system with origin points at Wink and Midland in the Permian Basin and delivery points at multiple Houston area locations. The joint venture owns a 71% undivided joint interest in the main pipeline segment between Midland and Houston. The Wink to Webster pipeline’s main segment began interim service operation in the fourth quarter of 2020, and the joint venture is expected to begin full commercial operations in the fourth quarter of 2021. Upon completion, this pipeline, which we refer to as the Wink to Webster pipeline, will be capable of transporting approximately 1,500,000 Bbl/d.
 
Investment in crude oil gathering system

We also own a 60% equity interest in OMOG JV LLC, a joint venture that owns Reliance Gathering, LLC, which owns and operates an in-basin crude oil gathering and transportation system in the Northern Midland Basin underpinned by long-term transportation agreements. The crude oil gathering and transportation system includes approximately 235 miles of crude oil gathering and regional transportation pipelines and approximately 200,000 barrels of crude oil storage in Midland, Martin, Andrews and Ector Counties, Texas. We refer to this joint venture as the OMOG joint venture. Over 150,000 gross acres in the Northern Midland Basin are dedicated to the system under long-term, fixed-fee agreements, some of which benefit from minimum volume commitments.

Investment in gas gathering and processing system

We also own a 50% equity interest in Amarillo Rattler, LLC, a joint venture that owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity, as of December 31, 2020, of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. We refer to this joint venture as the Amarillo Rattler joint venture. Amarillo Rattler also intends to construct and operate a new 60,000 Mcf⁄d cryogenic natural gas processing plant in Martin County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. However, development of the new processing plant has been postponed pending a recovery in commodity prices and activity levels. Diamondback has contracted for 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with the joint venture in exchange for Diamondback’s dedication of certain leasehold interests to that agreement.


3

Our Relationship with Diamondback

    As of December 31, 2020, our general partner had a 100% general partner interest in us, and Diamondback owned no common units and beneficially owned all of our 107,815,152 outstanding Class B units, representing approximately 72% of our total units outstanding. Diamondback also owns and controls our general partner.

We believe Diamondback views our partnership as an integral part of its strategy of remaining a premier, low-cost Permian operator. The fundamental role we play in Diamondback’s operational success allows us to capitalize on Diamondback’s expected Permian production trajectory and strong track record of accretive acquisitions. We plan to build our midstream infrastructure in concert with and in advance of Diamondback’s expected production trajectory in order to allow Diamondback the operational flexibility to execute on its development plan. We believe that Diamondback will continue to be a low cost producer as a result of its management expertise, premier asset base with a deep inventory of economic potential horizontal drilling locations, well capitalized balance sheet and operational execution track record. As such, we expect Diamondback’s production trajectory, along with Rattler’s declining capital needs, will drive free cash flow growth in the future. Our anticipated capital expenditures are mainly associated with building out infield gathering and capacity and contributions to equity joint ventures. Our contributions to our long-haul crude oil pipeline joint ventures are expected to be significantly lower than in the past as the related assets and projects are at or near their full length and capacity. Our visibility into Diamondback’s drilling and production plans will allow us to utilize a synchronized midstream development plan that optimizes capital spending and free cash flow generation.

Business Strategies

Our primary objective is to increase unitholder value by executing the following business strategies:

Serve as a significant provider of midstream services for Diamondback. We own and operate midstream infrastructure assets that handle a significant portion of Diamondback’s crude oil, natural gas and water-related gathering and handling needs in the Midland and Delaware Basins. Significant past investment in building or acquiring our midstream assets to support Diamondback’s historical production has positioned us for declining future operating capital expenditures to accommodate Diamondback’s volumes. Diamondback has dedicated approximately 395,000 gross acres to us through the Acreage Dedications. Pursuant to these dedications, we will continue to provide sourced water handling and gathering, produced water handling and disposal, crude oil transportation and gathering and natural gas gathering and compression services for Diamondback until 2034, and extended thereafter on a yearly basis unless terminated by a party. We expect that Diamondback’s development of its core areas, and therefore its need for midstream services, will continue on the Dedicated Acreage and we intend to utilize this relationship with Diamondback to drive free cash flow.

Focus on cash flow generation to fund our capital plan, support our distribution policy and maximize unitholder returns. Our operations are underpinned by high-margin, stable cash flow as a result of our long-term, fixed-fee contracts with Diamondback. In addition, other than our equity commitments in connection with our joint ventures, four of which are substantially complete, we expect to have low future operating capital expenditure requirements, which will allow us to generate free cash flow and make distribution payments to our common unitholders while limiting our reliance on the capital markets. A core component of our strategy is to maximize free cash flow while maintaining a conservative debt to equity ratio.

Emphasize providing midstream services under long-term, fixed-fee contracts to avoid direct commodity price exposure, mitigate volatility and enhance stability of our cash flow. Our commercial agreements with Diamondback are structured as long-term, fixed-fee contracts, which mitigates our direct exposure to commodity prices and enhances stability and predictability of our cash flow. We intend to pursue future opportunities that primarily utilize fixed-fee structures to insulate our cash flow from direct commodity price exposure.

Competitive Strengths

We have a number of competitive strengths that we believe will help us successfully execute our business strategies, including:

Fundamental, strategic relationship with Diamondback. We believe we are integral to Diamondback’s strategy and we believe the fundamental role we play in Diamondback’s operational success allows us to capitalize on Diamondback’s expected Permian production. We plan to build our midstream infrastructure in concert with and in advance of Diamondback’s expected production in order to allow Diamondback the operational flexibility to
4

execute on its development plan. We are a significant provider of midstream services to Diamondback with Acreage Dedications that spans a total of approximately 395,000 gross acres across all of our service lines and over the core of the Midland and Delaware Basins. Our visibility into Diamondback’s drilling and production plans allows us to utilize a synchronized midstream development plan that optimizes capital spending and free cash flow generation.

Experienced management team with an extensive track record of value creation. The management team of our general partner consists of executives from Diamondback and we believe their significant experience, successful track record and discipline in deploying capital at Diamondback distinguishes us from our peers. We believe that the expertise and success in the Permian of our general partner’s management team helps us deliver attractive unitholder returns.
 

Asset base located in the core of the Permian with highly visible underlying production. Our asset base is located in what we believe is the core of the Midland and Delaware Basins of the Permian and overlays Diamondback’s core development areas. These areas are characterized by high return single well economics that we believe are among the best in the Lower 48 and have a deep inventory of economic horizontal drilling locations. We believe our strategically located assets provide critical midstream infrastructure for Diamondback’s multi-year development plan, and we expect to benefit directly from Diamondback’s execution on its operational plan. The core location of our assets and the close proximity to other leading exploration and production operators provide additional opportunities to execute third party contracts for midstream services.

Structural and strategic alignment with unitholders. We are focused on creating differentiated unitholder value and providing strong return on and return of capital to unitholders. Through its ownership of Class B and common units in us and its ownership of membership interests in the Operating Company, Diamondback is our largest unitholder and has a 72% ownership interest in us and owns 100% of our general partner. As a result, Diamondback directly benefits if we grow free cash flow and distributions. We do not have incentive distribution rights or subordinated units, which we believe better aligns the interests of our unitholders with those of Diamondback. Additionally, we are structured as a partnership that elected to be treated as a corporation for tax purposes, which we believe increases stability and creates a more liquid trading market for our common units, given our access to a potentially broader unitholder base. We believe that our relationship with Diamondback and resulting alignment of strategic and operational interests is a differentiator in the public midstream sector and provides the optimal platform to pursue a balanced plan for value creation that benefits all unitholders equally.

High-margin business that generates significant, predictable free cash flow. Our revenue is generated as a result of our commercial agreements, which are fee-based and, as of December 31, 2020, include dedications of acreage in the Delaware Basin (approximately 185,000 gross acres) and the Midland Basin (approximately 210,000 gross acres). The fees charged under our commercial agreements are based upon the prevailing market rates at the time of execution with annual escalators (subject to potential adjustment by regulators). We believe our commercial agreements with Diamondback provide exposure to Diamondback’s production with no direct commodity price exposure, thus enhancing the predictability of free cash flow and our performance. We believe the current capacity of our assets relative to Diamondback’s production should result in minimal incremental operating capital expenditures to meet Diamondback’s anticipated volumes, and will result in significant long-term free cash flow generation that supports a self-funding model for our core business and the return of capital to unitholders through a distribution.

Financial flexibility and conservative capital structure. We have a conservative capital structure that we believe provides us with the financial flexibility to execute our business strategies. As of December 31, 2020, we had $545 million of liquidity, including $521 million of available borrowings under our credit agreement, and a debt to equity ratio of approximately 2.0 to 1.0. We believe that our significant liquidity and strong capital structure allows us to execute our strategy while limiting our reliance on the capital markets.

Competition

If and when we expand our crude oil, natural gas and water-related midstream services to third party producers, we will face a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store or market natural gas. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or NGLs.

5

Within the Dedicated Acreage, we do not compete with other midstream companies to provide Diamondback with midstream services as a result of our relationship with Diamondback and long-term dedications to our midstream assets. However, Diamondback may continue to use third party service providers for certain midstream services within the Dedicated Acreage until the expiration or termination of certain pre-existing dedications.

Seasonal Nature of Business

Demand for natural gas generally decreases during the summer months and increases during the winter months. The volumes of condensate produced at our processing facilities fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers or seasonal weather conditions, such as, for example, the recent severe winter storms in the Permian Basin may adversely affect our results of operations.

Regulation

The midstream services we provide are subject to regulations that may affect certain aspects of our business and the market for our services.

Environmental Matters

Our gathering pipelines, crude oil treating facilities and produced water facilities are subject to certain federal, state and local laws and regulations governing the emission or discharge of materials into the environment or otherwise relating to the protection of the environment.

As an owner or operator of these facilities, we comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

requiring the acquisition of permits to conduct regulated activities;
restricting the way we can handle or dispose of our materials or wastes;
limiting or prohibiting construction, expansion, modification and operational activities based on National Ambient Air Quality Standards, or NAAQS, and in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered species;
requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations;
enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued pursuant to such environmental laws and regulations; and
requiring noise, lighting, visual impact, odor or dust mitigation, setbacks, landscaping, fencing and other measures; and limiting or restricting water use.

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 remedial requirements and the issuance of orders enjoining current and future operations. Certain environmental statutes impose strict liability (i.e., no showing of “fault” is required) that may be joint and several for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for property damage or possibly personal injury allegedly caused by the release of substances or other waste products into the environment.

The historic 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 different from the amounts we currently anticipate. When possible, we attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to manage the costs of such compliance.

Our producers are subject to various environmental laws and regulations, including the ones described below, and could similarly face suspension of activities or substantial fines and penalties or other costs resulting from noncompliance with such laws and regulations. Any costs incurred to comply with or fines and penalties imposed related to alleged violations of environmental law that have the potential to impact or curtail production from the producers utilizing our midstream assets could subsequently reduce throughput on our systems and in turn adversely affect our business and results of operations.
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Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general.

Air Emissions

The federal Clean Air Act, or the CAA, as amended, and comparable state laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. Our operations are subject to the CAA, and comparable state and local requirements. We may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining preconstruction and operating permits and approvals. For example, on August 16, 2012, the EPA published final regulations under the CAA that establish new emission controls for oil and natural gas production and processing operations. See “– Climate Change.” Also, on June 3, 2016, the EPA published a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Compliance with these or other new legal requirements 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. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and natural gas operations.

Furthermore, on June 3, 2016, the EPA amended its New Source Performance standards to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, the Trump Administration directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, on August 13, 2020, the EPA issued amendments to its New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Various state, municipal and environmental groups have challenged the amendments and, on January 20, 2021, President Biden issued an executive order directing the EPA to review the amendments consistent with several policy objective, including reducing GHG emissions. Thus, substantial uncertainty exists regarding the scope of the New Source Performance standards for oil and natural gas operations. The 2016 New Source Performance standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

At the international level, in December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which took effect on February 19, 2021. The United States has indicated its plan to announce in advance of an April 22, 2021 climate summit its nationally determined contribution, or its commitment to reduce its national GHG emissions
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to meet this objective. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the commitments set forth in the international accord.
 
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the crude oil and natural gas we gather.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions, such as, for example, the recent severe winter storms in the Permian Basin, can interfere with our operations or Diamondback’s exploration and production operations, which in turn could affect demand for our services. Damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

Remediation of Hazardous Substances

Our operations are subject to environmental laws and regulations relating to the management and release of hazardous substances or solid wastes, including petroleum hydrocarbons. These laws generally regulate the generation, storage, treatment, transportation and disposal of solid and hazardous waste, and may impose strict, joint and several liabilities for the investigation and remediation of areas at a facility where hazardous substances may have been released or disposed. The Comprehensive Environmental Response, Compensation and Liability Act, as amended, which we refer to as CERCLA or the “Superfund” law, and analogous state laws, generally impose liability, without regard to fault or legality of the original conduct, on classes of persons who are considered to be responsible for the release of a “hazardous substance” into the environment. These persons include the current owner or operator of a contaminated facility, a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. Under CERCLA and comparable state statutes, persons deemed “responsible parties” are subject to strict liability that, in some circumstances, may be joint and several for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Despite the “petroleum exclusion” of CERCLA Section 101(14) that currently encompasses crude oil and natural gas, we may nonetheless handle hazardous substances within the meaning of CERCLA, or similar state statutes, in the course of our ordinary operations and, as a result, may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment. Therefore, governmental agencies or third parties may seek to hold us responsible under CERCLA and comparable state statutes for all or part of the costs to clean up sites at which such “hazardous substances” have been released.
 

Waste Handling

We also generate solid wastes, including hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, or RCRA, and comparable state statutes. The RCRA, as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of the RCRA, sometimes in
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conjunction with their own, more stringent requirements. Although most wastes associated with the development and production of crude oil and natural gas are exempt from regulation as hazardous wastes under the RCRA, such wastes may constitute “solid wastes” that are subject to the less stringent non-hazardous waste requirements. Moreover, the EPA or state or local governments may adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and natural gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and natural gas waste are not necessary at this time. Any changes in such laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We currently own or lease properties where petroleum hydrocarbons are being or have been handled for many years. Although we have utilized operating and disposal practices that were standard in the industry at the time, petroleum hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these petroleum hydrocarbons and wastes have been taken 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 or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to perform remedial operations to prevent future contamination. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of oil production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges

The Federal Water Pollution Control Act of 1972, also referred to as the Clean Water Act, or the CWA, and analogous state laws impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other oil and natural gas wastes, into navigable waters of the United States, as well as state waters. Pursuant to the CWA and analogous state laws, the discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules. The 2015 rule and the 2019 repeal are subject to several, ongoing legal challenges. Also, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the Clean Water Act. Several state and environmental groups have challenged the replacement rule and, on January 20, 2021, the Biden Administration directed the EPA and the Corps to review the rule. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act.

Spill prevention, control and countermeasure plan, or SPCC, requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In some instances, we may also be required to develop a Facility Response Plan that demonstrates our facility’s preparedness to respond to a worst case crude oil discharge. The CWA imposes substantial potential civil and criminal penalties for non-compliance.

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential
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environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Non-compliance with the CWA or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws. Additionally, we believe that compliance with existing permits and compliance with foreseeable new permit requirements will not have a material adverse effect on our financial condition or results of operations.

Hydraulic Fracturing

We do not conduct hydraulic fracturing operations, but substantially all of Diamondback’s crude oil and natural gas production on the Dedicated Acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our sourced water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, federal, state and local jurisdictions have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. Additionally, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices, which could spur initiatives to further regulate hydraulic fracturing. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.

Endangered Species

The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. On August 12, 2019, the U.S. Fish and Wildlife Service and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service jointly published final rules that, among other things, tighten the critical habitat designation process and eliminate certain automatic protections for threatened species going forward. Nevertheless, the designation of previously unprotected species, such as the dunes sagebrush lizard, in areas where we operate as threatened or endangered could result in the imposition of restrictions on our operations and consequently have a material adverse effect on our business.

Safety and Maintenance Regulation

We are subject to regulation by DOT under the Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

We are also subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline and Hazardous Materials Safety Administration, or PHMSA, has developed regulations implementing the Pipeline Safety Improvement Act that requires pipeline operators to implement integrity management programs, including more frequent inspections and other safety protections in areas where the consequences of potential pipeline accidents pose the greatest risk to people and their property.

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The Pipeline Safety and Job Creation Act, enacted in 2011, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, also known as the PIPES Act, enacted in 2016, amended the HLPSA and NGPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $218,647 and $2,186,465, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

PHMSA has undertaken rulemakings to address many areas of this legislation. For example, on October 1, 2019, PHMSA published final rules to expand its integrity management requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside High Consequence Areas. The rules, once effective, also extend reporting requirements to certain previously unregulated hazardous liquid gravity and rural gathering lines. Additional rulemakings are anticipated, including rulemakings to adjust repair criteria for gas transmission lines, to require inspection of gas pipelines following extreme events, and to extend regulatory safety requirements to certain gas gathering lines. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position. In addition, any material penalties or fines issued to us under these or other statutes, rules, regulations or orders could have an adverse impact on our business, financial condition, results of operation and cash flow.

States are largely preempted by federal law from regulating pipeline safety but may assume responsibility for enforcing intrastate pipeline regulations at least as stringent as the federal standards, and many states have undertaken responsibility to enforce the federal standards. The Railroad Commission of Texas is the agency vested with intrastate natural gas pipeline regulatory and enforcement authority in Texas. The Commission’s regulations adopt by reference the minimum federal safety standards for the transportation of natural gas. In addition, on December 17, 2019, the Commission adopted rules requiring that operators of gathering lines take “appropriate” actions to fix safety hazards. We do not anticipate any significant problems in complying with applicable federal and state laws and regulations in Texas. Our gathering pipelines have ongoing inspection and compliance programs designed to keep the facilities in compliance with pipeline safety and pollution control requirements.

In addition, we are subject to the requirements of OSHA and comparable state statutes, whose purpose is to protect the health and safety of workers, both generally and within the pipeline industry. Moreover, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. We and the entities in which we own an interest are also subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals. These regulations apply to any process which involves a chemical at or above specified thresholds, or any process which involves flammable liquid or gas, pressurized tanks, caverns and wells in excess of 10,000 pounds at various locations. Flammable liquids stored in atmospheric tanks below their normal boiling point without the benefit of chilling or refrigeration are exempt from these standards. Also, the Department of Homeland Security and other agencies such as the EPA continue to develop regulations concerning the security of industrial facilities, including crude oil and natural gas facilities. We are subject to a number of requirements and must prepare Federal Response Plans to comply. We must also prepare Risk Management Plans under the regulations promulgated by the EPA to implement the requirements under the CAA to prevent the accidental release of extremely hazardous substances. We have an internal program of inspection designed to monitor and enforce compliance with safeguard and security requirements. We believe that we are in compliance in all material respects with all applicable laws and regulations relating to safety and security.

FERC and State Regulation of Natural Gas and Crude Oil Pipelines

The FERC’s regulation of crude oil and natural gas pipeline transportation services and natural gas sales in interstate commerce affects certain aspects of our business and the market for our products and services.

 
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Natural Gas Gathering Pipeline Regulation

Section 1(b) of the Natural Gas Act of 1938, or NGA, exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We believe that our natural gas gathering facilities meet the traditional tests FERC has used to establish a pipeline’s status as a gathering pipeline and therefore our natural gas gathering facilities should not be subject to FERC jurisdiction. However, the distinction between FERC-regulated interstate transportation services and federally unregulated gathering services has been the subject of frequent litigation and varying interpretations, and FERC determines whether facilities are gathering facilities on a case by case basis, so the classification and regulation of our gathering facilities may be subject to change based on future determinations by FERC, the courts, or Congress. If FERC were to determine that all or some of our gathering facilities or the services provided by us are not exempt from FERC regulation, the rates for, and terms and conditions of, services provided by such facilities would be subject to regulation by FERC, which could in turn decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flow.

The Energy Policy Act of 2005, or EPAct 2005, amended the NGA to add an anti-market manipulation provision. Pursuant to FERC’s rules promulgated under EPAct 2005, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to FERC jurisdiction: (1) to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit a material fact; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 provided FERC with substantial enforcement authority, including the power to assess civil penalties of up to $1.0 million per day per violation, now increased for inflation to more than $1.2 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Failure to comply with the NGA, EPAct 2005 and the other federal laws and regulations governing our business can result in the imposition of administrative, civil and criminal remedies.

Texas regulation of gathering facilities includes various safety, environmental and ratable take requirements. Our gathering operations are subject to regulation by the Railroad Commission of Texas. Texas’s Natural Resources Code, or TNRC, provides that each person purchasing or taking for transportation crude oil or natural gas from any owner or producer shall purchase or take ratably, without discrimination in favor of any owner or producer over any other owner or producer in the same common source of supply offering to sell his crude oil or natural gas produced therefrom to such person. This statute has the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to transport natural gas.

The Railroad Commission of Texas’s regulations require operators of natural gas gathering lines to file several forms and provide financial assurance, and they also impose certain requirements on gathering system waste. Moreover, the Railroad Commission of Texas retains authority to regulate the installation, reclamation, operations, maintenance, and repair of gathering systems should the Railroad Commission of Texas choose to do so. Should the Railroad Commission of Texas exercise this authority, the consequences for us will depend upon the extent to which the authority is exercised. We cannot predict what effect, if any, the exercise of such authority might have on our operations.

Our natural gas gathering facilities are not subject to rate regulation or open access requirements by the Railroad Commission of Texas. However, the Railroad Commission of Texas requires us to register as pipeline operators, pay assessment and registration fees, undergo inspections and report annually on the miles of pipeline we operate.

Many of the producing states, including Texas, have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Further, additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but we could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Crude Oil Pipeline Regulation

Pipelines that transport crude oil in interstate commerce are subject to regulation by FERC pursuant to the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, and related rules and orders. The ICA requires, among other things, that tariff rates for common carrier crude oil pipelines be “just and reasonable” and not unduly discriminatory or preferential, and that such rates and terms and conditions of service be filed with FERC. The ICA permits interested persons to challenge proposed new or changed rates. FERC is authorized to suspend the effectiveness of such rates for up to seven months, though rates are typically suspended only for a nominal period and allowed to become effective, subject to refund and investigation. If, after investigation, FERC finds that the new or changed rate is unlawful, it may require the carrier to pay refunds for the period that the unlawful rate was in effect. FERC also may investigate, upon complaint or on its own motion, rates that are already in
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effect and may order a carrier to change its rates prospectively at the conclusion of the investigation. Upon an appropriate showing, a shipper may obtain reparations for damages sustained for a period of up to 2 years prior to the filing of a complaint. The rates charged for crude oil pipeline services are generally based on a FERC-approved indexing methodology, which allows a pipeline to charge rates up to a prescribed ceiling that changes annually based on the year-to-year change in the Producer Price Index for Finished Goods (PPI-FG). A rate increase within the indexed rate ceiling is presumed to be just and reasonable unless a protesting party can demonstrate that the rate increase is substantially in excess of the pipeline’s actual operating and maintenance costs, depreciation and a reasonable return on investment. The FERC reviews the index level every five years. The current index level is the PPI-FG, plus 1.23 percent, which is in effect until July 1, 2021. As an alternative to this indexing methodology, pipelines may also choose to support changes in their rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.

We have a FERC tariff on file to gather crude oil in interstate commerce and a Railroad Commission of Texas tariff on file to gather crude oil in intrastate commerce.

Other Oil and Natural Gas Industry Regulation

The State of Texas is engaged in a number of initiatives that may impact our operations directly or indirectly. To the extent that the State of Texas adopts new regulations that impact Diamondback, as our primary current customer, the impact of these regulations on Diamondback production activity may result in decreased demand from Diamondback for the services we provide.

We continue to monitor proposed and new regulations and legislation in all our operating jurisdictions to assess the potential impact on our company. Concurrently, we are engaged in extensive public education and outreach efforts with the goal of engaging and educating the general public and communities about the economic and environmental benefits of safe and responsible crude oil and natural gas development.

Employees

Neither we, the Operating Company nor our general partner has any employees. We rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner. All of the individuals that conduct our business, including our executive officers, are employed by Diamondback. As of December 31, 2020, Diamondback had approximately 732 fulltime employees performing services for our operations and activities.

Facilities

We own the Fasken Center which has over 421,000 net rentable square feet within its two office towers and associated assets in Midland, Texas. We, Diamondback and Viper Energy Partners LP, or Viper, are headquartered at the Fasken Center. Diamondback and unrelated third parties lease office space within the Fasken Center from us under long-term lease agreements. We also own field offices and related facilities in Midland and Reeves Counties, Texas. We believe that these facilities are adequate for our current operations.

Availability of Partnership Reports

Our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available free of charge on the Investor Relations page of our website at www.rattlermidstream.com as soon as reasonably practicable after such material is electronically filed with, or furnished to, the SEC. Information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.
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ITEM 1A.     RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were to occur, our business, financial condition, results of operations and cash available for distribution could be materially adversely affected. In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline and unitholders could lose all or part of their investment. Other risks are also described in “Items 1 and 2. Business and Properties” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Risks Related to Our Business

Our business and operations have been and will likely continue to be adversely affected by the ongoing COVID-19 pandemic and decreased demand for oil and natural gas.

The spread of COVID-19 caused, and is continuing to cause, severe disruptions in the worldwide and U.S. economies, including contributing to reduced global and domestic demand for oil and natural gas, which has had and will likely continue to have an adverse effect on our business, financial condition, results of operations and cash flows. The reduced demand for oil and natural gas, combined with pipeline capacity and storage constraints created by excess oil supply in the Permian Basin, depressed oil prices to all-time lows in April of 2020. Since then, oil prices have rebounded, but continue to remain at low levels and are expected to continue to be volatile as a result of the extent and duration of global production increases and the lack of storage capacity in the State of Texas, among other factors.

As a result of the reduction in crude oil demand, Diamondback announced reductions to its capital plans for 2020 and has indicated that it may decrease its budget further should commodity prices remain weak. We derive substantially all of our revenue from our commercial agreements with Diamondback, which do not contain minimum volume commitments. Reductions of Diamondback’s drilling and development plan on our Dedicated Acreage have had and will likely continue to have a direct and adverse impact on Diamondback’s demand for our midstream services and, consequently, our results of operations.

Moreover, since the beginning of January 2020, the COVID-19 pandemic has caused significant disruption in the financial markets both globally and in the United States. The continued spread of COVID-19 could also negatively impact the availability of key personnel necessary to conduct our business. If COVID-19 continues to spread or the response to contain or mitigate the COVID-19 pandemic, through the development and availability of effective treatments and vaccines, including the vaccines recently approved by the FDA for emergency use in the U.S., is unsuccessful, we could continue to experience material adverse effects on our business, financial condition and results of operations.

We derive substantially all of our revenue from Diamondback. If Diamondback changes its business strategy, alters its current drilling and development plan on the Dedicated Acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or sourced water with respect to which we perform midstream services, our revenue would decline and our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders would be materially and adversely affected.

We derive substantially all of our revenue from our commercial agreements with Diamondback, which do not contain minimum volume commitments, as well as volumes attributable to third-party interest owners that participate in Diamondback’s operated wells and are charged under short-term contracts at market sensitive rates. As a result, we are subject to the operational and business risks of Diamondback, the most significant of which include the following: a reduction in or slowing of Diamondback’s drilling and development plan on the Dedicated Acreage; the volatility of crude oil, natural gas and NGL prices; Diamondback’s costs of producing crude oil, natural gas and NGLs; the availability of capital on an economic basis to fund Diamondback’s exploration and development activities, if needed; drilling and operating risks, including potential environmental liabilities and litigation, associated with Diamondback’s operations on the Dedicated Acreage; downstream processing and transportation capacity constraints and interruptions, including the failure of Diamondback to have sufficient contracted processing or transportation capacity; and adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.

In addition, Diamondback is under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk that Diamondback could cancel its planned development on the Dedicated Acreage, prioritize planned development on acreage outside of the Dedicated Acreage, sell any of the Dedicated Acreage to a third party whose financial
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condition could be materially worse than Diamondback’s, breach its commitments with respect to future dedications or otherwise fail to pay or perform, including with respect to our commercial agreements. Any material non-payment or non-performance by Diamondback under our commercial agreements would have a significant adverse impact on our business, financial condition, results of operations and cash flow and could therefore materially adversely affect our ability to make cash distributions to our common unitholders.

Our commercial agreements with Diamondback provide for temporary or permanent releases of volumes or acreage from the Acreage Dedications under certain circumstances. Our commercial agreements also include provisions that permit Diamondback to suspend, reduce or terminate its obligations under each agreement if certain events occur. These events include force majeure events that would prevent us from performing some or all of the required services under the applicable agreement. Diamondback has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. Any temporary or permanent release of volumes or acreage from the Acreage Dedications or reduction, suspension, or termination of Diamondback’s obligations under our commercial agreements could materially adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions to our common unitholders.

As of December 31, 2020, we did not have any material customers other than Diamondback. However, we may in the future enter into material commercial contracts with other customers. To the extent we derive substantial income from or commit to capital projects to service new customers, each of the risks indicated above would apply to such arrangements and customers.

Our exposure to commodity price risk may change over time and we cannot guarantee the terms of any existing or future agreements for our midstream services with our customers.

We currently generate the majority of our revenues pursuant to fee-based agreements under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flow have little direct exposure to commodity price risk. However, Diamondback and our other customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a material adverse effect on our business.

We may not have sufficient cash to pay any quarterly distribution on our common units and, regardless of whether we have sufficient cash, we may choose not to pay any quarterly distribution on our common units.

We may not generate sufficient cash to support or pay any distribution to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. The amount we will be able to distribute on our common units will depend on the amount of cash we receive from the Operating Company, which in turn will principally depend on the amount of cash the Operating Company generates from our operations, which will fluctuate from quarter to quarter based on, among other things: market prices of crude oil, natural gas and NGLs and their effect on Diamondback’s drilling and development plan on the Dedicated Acreage and the volumes of hydrocarbons that are produced on the Dedicated Acreage and for which we provide midstream services; Diamondback’s and our other customers’ ability to fund their drilling and development plan on the Dedicated Acreage; downstream processing and transportation capacity constraints and interruptions; the levels of our operating expenses, maintenance expenses and general and administrative expenses; regulatory action affecting the supply of, or demand for, crude oil, natural gas, NGLs and water; regulatory action affecting our operating costs and the rates we can charge for our midstream services, including the rates that EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG can charge for their transportation, gathering, processing and terminal services, as applicable; prevailing economic conditions; and adverse weather conditions.

In addition, the actual amount of cash we have available for distribution depends on other factors, some of which are beyond our control, including: the level and timing of our capital expenditures, including capital calls associated with any investment we make in our joint ventures; our debt service requirements and other liabilities; our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay distributions; fluctuations in our working capital needs; restrictions on distributions contained in any of our debt agreements; the cost of acquisitions, if any; the fees and expenses of our general partner and its affiliates (including Diamondback) that we are required to reimburse; the amount of cash reserves established by our general partner; our cash flow; and other business risks affecting our cash levels.

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The board of directors of our general partner has modified our cash distribution policy and may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions on our common units at all.

The board of directors of our general partner may change our cash distribution policy at any time at its discretion and could elect not to pay distributions on our common units for one or more quarters. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our common unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited duties to our common unitholders, which may permit it to favor its own interests or the interests of Diamondback to the detriment of our common unitholders. For information regarding our distribution policy and the recent modifications, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations.

We own interests in certain pipeline projects and other joint ventures, and we may in the future enter into additional joint ventures, and our control of such entities is limited by provisions of the limited partnership and limited liability company agreements of such entities and by our percentage ownership in such entities.

We have ownership interests in several joint ventures, including the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG joint ventures, and we may enter into other joint venture arrangements in the future. While we own equity interests and have certain voting rights with respect to our joint ventures, we do not act as operator of or control our joint ventures (including our 60% interest in the OMOG joint venture), each of which is operated by another joint venture partner. We have limited ability to influence the business decisions of these entities, and it may therefore be difficult or impossible for us to cause the joint venture to take actions that we believe would be in our or the relevant joint venture’s best interests. 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 which could adversely affect our ability to make distributions to our common unitholders. In addition, our joint venture partners may not satisfy their financial obligations to the joint venture and may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture.

These joint ventures also have internal control environments independent of our oversight and review. If our joint venture partners have control deficiencies in their accounting or financial reporting environments, it may result in inaccuracies in the reporting for our percentage of the financial results for the joint venture, which may result in material misstatements in our reported consolidated financial results that could result in the need to restate and reissue previously issued consolidated financials filed with the SEC.

We are also unable to control the amount of cash we receive from the operation of these entities, which affects our ability to make distributions to our common unitholders. Joint venture arrangements may also restrict our operational and organizational flexibility and our ability to manage risk, which could have a material and adverse effect on our business, cash flow and results of operations.

 
Dedicated Acreage may be lost as a result of title defects in the properties in which Diamondback invests.

When acquiring oil and natural gas leases, Diamondback may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, Diamondback may rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless. If Diamondback fails to cure any title defects, it may be delayed or prevented from utilizing the associated mineral interest which could result in a decrease in the volumes on our systems and an associated decrease in our revenues.
We may not own in fee the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
We may not own in fee the land on which our midstream systems have been constructed. We own in fee less than 5% of the land on which our midstream systems have been constructed, with the remainder held by surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these
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rights, through our inability to renew rights-of-way, surface leases or other easement rights or otherwise, could have a material adverse effect on our business, financial condition, results of operations, cash flow and ability to make cash distributions.

Our midstream assets are currently located exclusively in the Permian Basin in Texas, making us vulnerable to risks associated with operating in a single geographic area.

Our midstream assets are currently located exclusively in the Permian Basin in Texas. As a result of this concentration, we are disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, market limitations, water shortages or restrictions, drought related conditions or other weather-related conditions, such as, for example, the recent severe winter storms in the Permian Basin, or interruption of the processing or transportation of crude oil, natural gas and water. If any of these factors were to impact the Permian Basin more than other producing regions, our business, financial condition, results of operations and ability to make cash distributions could be adversely affected relative to other midstream companies that have a more geographically diversified asset portfolio.

Oil and natural gas producers’ operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water. Restrictions on our ability to obtain water could reduce demand for our water services, which could have an adverse effect on our cash flow.

Water is an essential component of oil and natural gas production during both the drilling and hydraulic fracturing processes. However, the availability of suitable water supplies may be limited by prolonged drought conditions and changing laws and regulations relating to water use and conservation. For example, in recent years, Texas has experienced extreme drought conditions. As a result of this severe drought, some local water districts have begun restricting the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supply. A reduction in the availability of water could impact the water services we provide and, as a result, our financial condition, results of operations and cash available for distribution could be adversely affected.

If third-party pipelines or other facilities interconnected, or expected to be interconnected, to our midstream systems become partially or fully unavailable, or if the volumes we gather or treat do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders could be adversely affected.

We depend upon third-party pipelines and associated operations to provide delivery options from our pipelines. Because we do not control these pipelines and associated operations, their continuing operation is not within our control. If any pipeline were to become unavailable for current or future volumes of crude oil or refined products due to repairs, damage to the facility, lack of capacity, shut in by regulators or any other reason, or if the volumes we gather or transport do not meet the quality requirements of such pipelines or facilities, our business, financial condition, results of operations, cash flow and ability to make distributions to our common unitholders could be adversely affected.

Increased competition from other companies that provide midstream 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 systems compete for third party customers primarily with other crude oil and natural gas gathering systems and sourced and produced water service providers. Some of our competitors have greater financial resources and may now, or in the future, have access to greater supplies of crude oil, natural gas and sourced water than we do. Some of these competitors may expand or construct gathering systems that would create additional competition for the services we would provide to third party customers. In addition, potential third party customers may develop their own gathering systems instead of using ours. Moreover, Diamondback and its affiliates are not limited in their ability to compete with us, except with respect to the Acreage Dedications contained in our commercial agreements. Further, hydrocarbon fuels compete with other forms of energy available to end-users, including electricity and coal. Increased demand for such other forms of energy at the expense of hydrocarbons could lead to a reduction in demand for our services. All of these competitive pressures could make it more difficult for us to 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 and ability to make quarterly cash distributions to our common unitholders.


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Our construction of new midstream assets or the acquisitions of assets or businesses may not result in revenue increases and may be subject to regulatory, environmental, political, contractual, legal and economic risks, which could adversely affect our cash flow, results of operations and financial condition and, as a result, our ability to distribute cash to unitholders.

The construction of additions or modifications to our existing systems and the expansion into new production areas to service Diamondback involve numerous regulatory, environmental, political, contractual, legal and economic uncertainties beyond our control. For instance, we may not be able to construct in certain locations due to setback requirements, expand certain facilities that are deemed to be part of a single source or aggregate crude oil and natural gas production facility emissions according to permitting requirements. As a result, we may not be able to complete such projects on schedule, at the budgeted cost or at all. Similarly, if we build additional gathering assets, the construction may occur over an extended period of time or occur in an area where anticipated growth does not materialize. In either case, we may not receive any material increases in revenues or achieve our expected investment return. Further the construction of additions to our existing assets may require us to obtain new rights-of-way, surface use agreements or other real estate agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure, obtain them in a cost-efficient manner or capitalize on other attractive expansion opportunities.

Acquisitions of assets or businesses may require the expenditure of significant amounts of capital and involve potential risks that may disrupt our business, including the following, among other things: mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies; an inability to successfully integrate the acquired assets or businesses; the assumption of unknown liabilities, including exposure to potential lawsuits; limitations on rights to indemnity from the seller; the diversion of management’s and employees’ attention from other business concerns; unforeseen difficulties operating in new geographic areas; and customer or key employee losses at the acquired businesses.

We, Diamondback or any third party customers may incur significant liability under, or costs and expenditures to comply with, a broad range of federal, state and local regulations, including those relating to environmental, commerce, transportation and health and safety matters, which are complex and subject to frequent change. We are subject to regulation by multiple governmental agencies, which could adversely impact our business, financial condition and results of operations.

As an owner and operator of gathering systems, we are directly or indirectly subject to regulation by multiple federal, state and local governmental agencies. Risks and uncertainties related to such regulation include:

The historic trend of more expansive and stricter environmental laws and regulations, including those related to GHGs and climate change, air quality, water quality, the storage, treatment and disposal of waste, including produced water, protection of endangered or threatened species, and the remediation of contaminated soil and groundwater, may continue in the long-term potentially resulting in increased costs of doing business;
The rates charged for gathering service over our regulated crude oil assets are subject to review and reporting by FERC and the Texas Railroad Commission, which could adversely affect our revenues;
A change by FERC in policy or the jurisdictional characterization of some of our assets may result in increased regulation of our assets, which may cause our operating expenses to increase, limit the rates we charge for certain services and decrease the amount of cash we have available for distribution;
Federal and state legislative and regulatory initiatives relating to pipeline safety that require the use of new or more stringent safety controls or result in more stringent enforcement of applicable legal requirements could subject us to increased capital costs, operational delays and costs of operation;
Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas production by Diamondback and our other customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues;
Federal and state legislative and regulatory initiatives intended to address seismic activity could restrict our ability to dispose of produced water gathered from Diamondback and our other customers, which could have a material adverse effect on our business;
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the crude oil and natural gas that we gather while potential physical effects of climate change could disrupt Diamondback’s and our other customers’ production and cause us to incur significant costs in preparing for or responding to those effects; and
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Certain plant or animal species are or could be designated as endangered or threatened, which could have a material impact on our and Diamondback’s operations.
Proposals and proceedings that affect the midstream industry are regularly considered by Congress, as well as by state legislatures and federal and state regulatory commissions, agencies and courts. We cannot predict when or whether any such proposals or proceedings may become effective or the magnitude of the impact changes in laws and regulations may have on our business. However, additions to the regulatory burden on our industry can increase our cost of doing business and adversely impact our business, financial condition, results of operations and cash available for distributions. See “Items 1 and 2. Business and Properties-Regulation” for a description of certain laws and regulations that affect or could affect our operations.

The results of the 2020 U.S. presidential and congressional elections may create regulatory uncertainty for the oil and natural gas industry. Changes in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows.

The results of the 2020 U.S. presidential election, as well as a closely divided Congress, may create regulatory uncertainty in the oil and natural gas industry. During his first weeks in office, President Biden has issued several executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and pause new oil and natural gas leasing on public lands. It remains unclear what additional actions President Biden will take and what support he will have for any potential legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our or our operators’ business. However, such actions could significantly increase our operators’ costs or impair their ability to explore and develop other projects, which could adversely impact our business, financial condition and cash flows.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. The occurrence of a significant accident or other event that is not fully insured could curtail our operations and have a material adverse effect on our ability to make cash distributions and, accordingly, the market price for our common units.

Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of sourced water, including: damage to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties; leaks of crude oil, natural gas or NGLs or losses of crude oil, natural gas or NGLs as a result of the malfunction of, or other disruptions associated with, equipment or facilities; fires, ruptures and explosions; and other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for; injury or loss of life; damage to and destruction of property, natural resources and equipment; pollution and other environmental damage; regulatory investigations and penalties; suspension of our operations; and repair and remediation costs.

 
We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition, results of operations, cash flow and ability to make cash distributions.

A shortage of equipment and skilled labor could reduce equipment availability and labor productivity and increase labor and equipment costs, which could have a material adverse effect on our business and results of operations.

Our gathering and other midstream services require special equipment and laborers who are skilled in multiple disciplines, such as equipment operators, mechanics and engineers, among others. If we experience shortages of necessary equipment or skilled labor in the future, our labor and equipment costs and overall productivity could be materially and adversely affected. If our equipment or labor prices increase or if we experience materially increased health and benefit costs for employees, our business and results of operations could be materially and adversely affected.

The loss of key personnel could adversely affect our ability to operate.

We depend on the services of a relatively small group of individuals, all of whom are employees of Diamondback and provide services to us pursuant to the services and secondment agreement. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. The loss of the services of these individuals who represent all of our
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general partner’s senior management could have a material adverse effect on our business, financial condition, results of operations, cash flow and ability to make cash distributions.

Neither we, the Operating Company nor our general partner has any employees, and we rely solely on the employees of Diamondback to manage our business. The management team of Diamondback, which includes the individuals who manage us, also perform similar services for Diamondback and certain of its affiliates, and thus are not solely focused on our business.

Neither we, the Operating Company nor our general partner has any employees, and we rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner. Diamondback provides similar activities with respect to its own assets and operations. Because Diamondback provides services to us that are similar to those performed for itself and its affiliates, Diamondback may not have sufficient human, technical and other resources to provide those services at a level that Diamondback would be able to provide to us if it were solely focused on our business and operations and those of its affiliates. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself or others in providing its services. If the employees of Diamondback and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our common unitholders may be reduced.

In the future we may face increased obligations relating to the closing of our produced water facilities and may be required to provide an increased level of financial assurance to guaranty the appropriate closure activities occur for a produced water facility.
Obtaining a permit to own or operate produced water facilities generally requires us to establish performance bonds, letters of credit or other forms of financial assurance to address clean-up and closure obligations. As we acquire additional produced water facilities or expand our existing produced water facilities, these obligations will increase. Additionally, in the future, regulatory agencies may require us to increase the amount of our closure bonds at existing produced water facilities. We have accrued approximately $15.1 million on our balance sheet related to our future closure obligations of our produced water facilities and oil and gas gathering systems as of December 31, 2020. However, actual costs could exceed our current expectations, as a result of, among other things, federal, state or local government regulatory action, increased costs charged by service providers that assist in closing produced water facilities and additional environmental remediation requirements. The obligation to satisfy increased regulatory requirements associated with our produced water facilities could result in an increase of our operating costs and affect our ability to make distributions to our common unitholders.

Our businesses and results of operations are subject to seasonal fluctuations, which could result in fluctuations in our operating results and common unit price.

Our business is subject to seasonal fluctuations. Demand for natural gas generally decreases during the spring and fall months and increases during the summer and winter months. The volumes of condensate produced at our processing facilities fluctuate seasonally, with volumes generally increasing in the winter months and decreasing in the summer months as a result of the physical properties of natural gas and comingled liquids. Severe or prolonged summers may adversely affect our results of operations.

Our operations depend heavily on electrical power, internet and telecommunication infrastructure and information and computer systems. If any of these systems are compromised or unavailable, our business could be adversely affected.

We are heavily dependent on electrical power, internet and telecommunications infrastructure and our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such infrastructure, systems or programs were to fail or become unavailable or compromised, or create erroneous information in our hardware or software network infrastructure, our ability to safely and effectively operate our business will be limited and any such consequence could have a material adverse effect on our business.

A terrorist attack, cyber-attack, armed conflict or health threats could harm our business.

Terrorist activities, cyber-attacks, anti-terrorist efforts, other armed conflicts involving the United States or other countries or global or national health concerns, including the outbreak of pandemic or contagious disease such as the coronavirus, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a
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reduction in our revenues. Crude oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if infrastructure integral to our operations is destroyed or damaged. Costs for insurance and other security may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.

 
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain midstream activities. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to manage gathering and transportation systems, process and record financial and operating data and to communicate with our employees and business service providers. The technologies needed to conduct midstream activities make certain information the target of theft or misappropriation. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also has increased. A cyber incident involving our information systems and related infrastructure, or that of our business service providers, could disrupt our business plans and negatively impact our operations. Our implementation of various controls and processes, including globally incorporating a risk-based cyber security framework, to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. We maintain specialized insurance for possible liability resulting from a cyberattack on our assets, however, we cannot assure you that the insurance coverage will be adequate to cover claims that may arise, or that we will be able to maintain adequate insurance at rates we consider reasonable. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.

If we are deemed an “investment company” under the Investment Company Act of 1940, it could have a material adverse effect on our business and the price of our common units.
Our assets include interests in certain pipeline projects and other joint ventures. If a sufficient amount of our assets, such as our ownership interests in other midstream ventures, now owned or in the future acquired, are deemed to be “investment securities” within the meaning of the Investment Company Act of 1940, we may have to register as an “investment company” under the Investment Company Act, claim an exemption, obtain exemptive relief from the SEC or modify our organizational structure or our contract rights. Registering as an “investment company” could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage, and require us to add additional directors who are independent of us or our affiliates. The occurrence of some of these events would adversely affect the price of our common units and could have a material adverse effect on our business.
Risks Related to Our Indebtedness

We have in the past incurred, and we expect in the future to continue to incur, borrowings under the Operating Company’s revolving credit facility. Unless we are able to repay borrowings under the revolving credit facility with cash flow from operations or other sources, including proceeds from equity and debt offerings, implementing our capital programs may require an increase in our total leverage through additional debt issuances. In addition, a reduction in availability under the revolving credit facility and the inability to otherwise obtain financing for our capital programs could require us to curtail our capital expenditures.

As a result of our cash distribution policy, we have limited cash available to reinvest in our business or to fund acquisitions and have historically relied on availability under the Operating Company’s revolving credit facility to fund a portion of our capital expenditures and for other purposes. We expect that we will continue to fund a portion of our capital expenditures and other needs with borrowings under the revolving credit facility and from the proceeds of debt and equity offerings. In the past, we have created availability under the revolving credit facility by repaying outstanding borrowings with the proceeds from equity and debt offerings. We cannot assure you that we will choose to or be able to access the capital markets to repay any such future borrowings. If the availability under the revolving credit facility were reduced, and we were otherwise unable to secure other sources of financing, we may be required to curtail our capital expenditures, which could result in an inability to complete acquisitions or finance the capital expenditures necessary to replace our reserves.


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Our level of indebtedness could limit our flexibility to obtain financing and to pursue other business opportunities and could adversely affect our financial condition and prevent us from fulfilling our obligations under the Notes and our other indebtedness.

As of December 31, 2020, we had total long-term debt of $579.0 million, consisting of $500.0 million aggregate principal amount of our outstanding 5.625% Senior Notes due 2025, which we refer to herein as the notes, and $79.0 million in outstanding borrowings under the Operating Company’s revolving credit facility. As of December 31, 2020, the borrowing base under the Operating Company’s revolving credit facility was $600.0 million. We and the Operating Company may in the future incur significant additional indebtedness under our revolving credit facility or otherwise in order to fund our operations, fund capital contributions related to our joint ventures or for other purposes.

Our level of debt could have important consequences to us, including the following: it may become more difficult for us to satisfy our obligations with respect to the notes, including any repurchase obligations that may arise thereunder; 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; we may be vulnerable to interest rate increases, as the borrowings under the Operating Company’s revolving credit facility are at variable interest rates; our vulnerability to general adverse economic and industry conditions could potentially increase; the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments; we may be placed at a competitive disadvantage compared to our competitors that are less leveraged and, therefore, our competitors may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing; our debt covenants may also limit management’s discretion in operating our business and our flexibility in planning for, and reacting to, changes in the economy and in our industry; our ability to access the capital markets to raise capital on favorable terms could be limited; our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements), acquisitions, general corporate or other purposes may be impaired or such financing may not be available on favorable terms; we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and our flexibility in responding to changing business and economic conditions may be limited.

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 any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Restrictive covenants in the Operating Company’s revolving credit facility, the indenture governing the notes and future debt instruments may limit our ability to respond to changes in market conditions or pursue business opportunities.

The Operating Company’s revolving credit facility and the indenture governing our outstanding notes contain, and the terms of any future indebtedness may contain, restrictive covenants that limit our and the Operating Company’s ability to, among other things: incur or guarantee additional debt; redeem or repurchase units or make distributions under certain circumstances; make certain investments and acquisitions; incur certain liens or permit them to exist; issue redeemable equity; voluntarily redeem or prepay debt, including the notes; enter into certain types of transactions with affiliates; designate certain of our subsidiaries as unrestricted subsidiaries; create unrestricted subsidiaries; sell or discount receivables; merge or consolidate with another company; and transfer, sell or otherwise dispose of assets.

We may be prevented from taking advantage of business opportunities that arise because of the limitations imposed on us and the Operating Company by the restrictive covenants contained in the revolving credit facility and the indenture that governs the notes. In addition, the revolving credit facility requires us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

Our and the Operating Company’s future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. A breach of any of these restrictive covenants could result in default under the revolving credit facility. If a default occurs, the lenders under the revolving credit facility may elect to declare all borrowings outstanding, together with accrued interest and other fees, to be immediately due and payable, which would result in an event of default under the indenture governing the notes. The lenders will also have the right in these circumstances to terminate any commitments they have to provide further borrowings. If we
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and the Operating Company are unable to repay outstanding borrowings when due, the lenders under the revolving credit facility will also have the right to proceed against the collateral granted to them to secure the indebtedness. If the indebtedness under the revolving credit facility and the notes were to be accelerated, we cannot assure you that our assets would be sufficient to repay in full that indebtedness.

Servicing our indebtedness requires a significant amount of cash, and we may not have sufficient cash flow from our business to pay our substantial indebtedness.

Our ability to make scheduled payments of the principal of, to pay interest on or to refinance our indebtedness depends on our future performance, which is subject to economic, financial, competitive and other factors beyond our control. We are dependent on cash flow generated by the Operating Company to repay the notes. The Operating Company’s business may not generate cash flow from operations in the future sufficient to service our debt and make necessary capital expenditures. If the Operating Company is unable to generate such cash flow, we may be required to adopt one or more alternatives, such as reducing or delaying capital expenditures, selling assets, restructuring debt or obtaining additional capital on terms that may be onerous or highly dilutive. However, we cannot assure you that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations. In the absence of such cash flows, we could have substantial liquidity problems and might be required to sell material assets or operations to attempt to meet our debt service and other obligations. The Operating Company’s revolving credit facility and the indenture governing our outstanding notes restrict our ability to use the proceeds from asset sales. We may not be able to consummate those asset sales to raise capital or sell assets at prices that we believe are fair, and proceeds that we do receive may not be adequate to meet any debt service obligations then due. Our ability to refinance our indebtedness will depend on the capital markets and our financial condition at the time. We may not be able to engage in any of these activities or engage in these activities on desirable terms, which could result in a default on our debt obligations and have an adverse effect on our financial condition.

If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.

Our ability to obtain financings and trade credit and the terms of any financings or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales, liquidity, asset quality and cost structure. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our or the Operating Company’s borrowing costs.

Increases in interest rates could adversely affect our business.

The terms of the Operating Company’s credit agreement provide for interest at a per annum rate that is based on the prime rate or LIBOR, in each case plus an applicable margin. LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. Accordingly, our interest expense for any particular period will fluctuate based on LIBOR and other variable interest. If interest rates increase, our results of operations, cash flow and financial condition and, as a result, our ability to make cash distributions to our common unitholders, could be materially adversely affected by significant increases in interest rates.

On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, a steering committee comprised of large US financial institutions, is considering replacing U.S. dollar LIBOR with the Secured Overnight Financing Rate, or SOFR, a new index calculated by short-term repurchase agreements, backed by Treasury securities. It is unknown at this time whether SOFR will attain market acceptance as a replacement for LIBOR. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere.

It remains unclear whether the cessation of LIBOR will be delayed due to COVID-19 or what form any delay may take, and there are no assurances that there will be a delay. It is also unclear what the duration and severity of COVID-19 will be, and whether this will impact LIBOR transition planning. COVID-19 may also slow regulators’ and others’ efforts to develop and implement alternative reference rates, which could make LIBOR transition planning more difficult, particularly if the cessation of LIBOR is not delayed but an alternative reference rate does not emerge as industry standard.



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 Risks Inherent in an Investment in Us

Diamondback owns and controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Diamondback, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

Diamondback owns and controls our general partner and appoints all of the directors of our general partner. All of the executive officers and certain of the directors of our general partner are also officers and/or directors of Diamondback. Although our general partner has a duty to manage us in a manner that it believes is not adverse to our interest, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner that is in the best interests of Diamondback. Therefore, conflicts of interest may arise between Diamondback or any of its affiliates, including our general partner, on the one hand, and us and/or any of our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders. These conflicts include the following situations, among others:

our general partner is allowed to take into account the interests of parties other than us, such as Diamondback, in exercising certain rights under our partnership agreement;
Diamondback and other affiliates of our general partner may compete with us as neither our partnership agreement nor any other agreement requires Diamondback to pursue a business strategy that favors us;
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties;
our partnership agreement limits our general partner’s liabilities and 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;
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
our general partner determines the amount and timing of asset purchases and sales, borrowings, issuances of additional partnership securities and the level of cash reserves, each of which can affect the amount of cash that is distributed to our common unitholders;
cost reimbursements, which are determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided may be substantial and will reduce the amount of cash we have available for distribution to our common unitholders;
contracts between us, on the one hand, and our general partner and its affiliates, on the other hand, will not be the result of arm’s-length negotiations;
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 its affiliates on our behalf;
our general partner intends to limit its liability regarding our contractual and other obligations;
our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 97% of the common units and Class B units, taken together (which threshold will be permanently reduced to 80% if our general partner and its affiliates (including Diamondback) collectively own less than 75% of the common units and Class B units, taken together) and such right may be exercised at an undesirable time or price;
common unitholders have no right to enforce the obligations of our general partner and its affiliates under agreements with us; and
our general partner decides whether to retain separate counsel, accountants or others to perform services for us.
By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including being subject to the risks discussed above.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, or initially remove our general partner without its consent, even if they are dissatisfied.

Unlike the holders of common stock in a corporation, common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Common unitholders have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of
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directors of our general partner, including the independent directors, is chosen entirely by Diamondback, as a result of it owning our general partner, and not by our common unitholders. Unlike publicly traded corporations, we do not conduct annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which our common units trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

If our common unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. The vote of the holders of at least 66 2/3% of all outstanding units, including any units owned by our general partner and its affiliates, voting as a single class, is required to remove our general partner. In addition, any vote to remove our general partner must provide for the election of a successor general partner by the holders of a majority of the outstanding units, voting together as a single class. As of December 31, 2020, Diamondback owned 107,815,152 of our Class B units representing 72% of voting interests in us. This gives Diamondback the ability to prevent the removal of our general partner.

Furthermore, common unitholders’ voting rights are further restricted by our partnership agreement provision providing 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 vote on any matter.
 
Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of our management.

 
Our 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 without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and the executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and the executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the common unitholders.

Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for our obligations.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our common 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 any 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. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted.

A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware, to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

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

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects: the proportionate ownership interest of common unitholders in us immediately prior to the issuance will decrease; the amount of cash distributions on each common unit may decrease; the relative voting strength of each previously outstanding common unit may be diminished; and the market price of the common units may decline. The issuance by us of an additional general partner interest may have the following effects, among others, if
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such general partner interest is issued to a person who is not an affiliate of Diamondback: management of our business may no longer reside solely with our current general partner; and affiliates of the newly admitted general partner may compete with us, and neither that general partner nor such affiliates will have any obligation to present business opportunities to us.
    
There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

In accordance with Delaware law and the provisions of our partnership agreement, we may issue additional partnership interests that are senior to the common units in right of distribution, liquidation and voting. The issuance by us of units of senior rank may (i) reduce or eliminate the amount of cash available for distribution to our common unitholders; (ii) diminish the relative voting strength of the total common units outstanding as a class; or (iii) subordinate the claims of the common unitholders to our assets in the event of our liquidation.

Our partnership agreement includes exclusive forum, venue and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement also provides that any unitholder bringing an unsuccessful action will be obligated to reimburse us for any costs we have incurred in connection with such unsuccessful action.

Our partnership agreement is governed by Delaware law. Our partnership agreement includes exclusive forum, venue and jurisdiction provisions designating Delaware courts as the exclusive venue for most claims, suits, actions and proceedings involving us or our officers, directors and employees. In addition, if any person brings any of the aforementioned claims, suits, actions or proceedings and such person does not obtain a judgment on the merits that substantially achieves, in substance and amount, the full remedy sought, then such person shall be obligated to reimburse us and our affiliates for all fees, costs and expenses of every kind and description, including but not limited to all reasonable attorneys’ fees and other litigation expenses, that the parties may incur in connection with such claim, suit, action or proceeding. By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of Delaware courts.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to permit the general partner to redeem the units of certain unitholders.

Our general partner may amend our partnership agreement, as it determines necessary or advisable, to obtain proof of the nationality, citizenship or other related status of our limited partners (and their owners, to the extent relevant) and to permit our general partner to redeem the units held by any person (i) whose nationality, citizenship or related status creates substantial risk of cancellation or forfeiture of any of our property and/or (ii) who fails to comply with the procedures established to obtain such proof. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

    The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.

Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have provided certain registration rights to Diamondback. Pursuant to these registration rights, we have agreed to register, under the Securities Act, all of the common units owned by Diamondback and its assignees for resale (including common units issuable in exchange for Class B units and our OpCo units). Under our partnership agreement, our general partner and its affiliates also have registration rights relating to the offer and sale of any common units that they hold.

For as long as we are an emerging growth company, we are not required to comply with certain disclosure requirements, including those relating to accounting standards and disclosure about our executive compensation and internal control auditing requirements that apply to other public companies.

We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we are not required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm
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rotation or a supplement to the auditor’s report in which the auditor would be required to provide additional information about the audit and the financial statements of the issuer, (iii) comply with any new audit rules adopted by the Public Company Accounting Oversight Board after April 5, 2012 unless the SEC determines otherwise or (iv) provide certain disclosures regarding executive compensation required of larger public companies.
 
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential common unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our common units.

We are required to comply with the SEC’s rules implementing Sections 302 and 404 of the Sarbanes-Oxley Act of 2002, which requires our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting, with auditor attestation of the effectiveness of our internal controls over financial reporting beginning with our Annual Report on Form 10-K for the year in which we cease to qualify as an emerging growth company. Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our common units.

Nasdaq does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

Our common units are listed on the Nasdaq Global Select Market. Because we are a publicly traded partnership, Nasdaq does not require us to have a majority of independent directors on our general partner’s board of directors or to establish 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 Nasdaq’s stockholder approval rules that apply to a corporation. Accordingly, unitholders do not have the same protections afforded to stockholders of certain corporations that are subject to all of Nasdaq’s corporate governance requirements.

We are treated as a corporation for U.S. federal income tax purposes and our cash available for distribution to our common unitholders may be substantially reduced.

We are a Delaware limited partnership and, on May 24, 2019, we elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to tax as a corporation at the corporate tax rate. While we expect to generate net operating losses to offset taxable income through 2021, there is no guarantee that we will not have any taxable income as a result of our equity interests in the Operating Company. Because an entity-level tax is imposed on us due to our status as a corporation for U.S. federal income tax purposes, our distributable cash flow may be substantially reduced by our tax liabilities.
Distributions to common unitholders may be taxable as dividends.
Because we are treated as a corporation for U.S. federal income tax purposes, if we make distributions to our common unitholders from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions will be treated as distributions on corporate stock for U.S. federal income tax purposes, and generally be taxable to our common unitholders as ordinary dividend income for U.S. federal income tax purposes (to the extent of our current and accumulated earnings and profits). Such dividend distributions paid to non-corporate U.S. unitholders will be subject to U.S. federal income tax at preferential rates, provided that certain holding period and other requirements are satisfied. Any portion of our distributions to common unitholders that exceeds our current and accumulated earnings and profits as computed for U.S. federal income tax purposes will constitute a non-taxable return of capital distribution to the extent of a unitholder’s basis in its common units, and thereafter as gain on the sale or exchange of such common units.
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Future U.S. tax legislations may adversely affect our business, financial condition, results of operations, and cash flow.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available to our customers, including Diamondback, with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, financial condition, results of operations, and cash flows.
ITEM 1B.     UNRESOLVED STAFF COMMENTS

None.

ITEM 3.     LEGAL PROCEEDINGS

Due to the nature of our business, we may be, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. See “Item 8. Financial Statements and Supplementary Data—Note 16. Commitments and Contingencies.”
ITEM 4.     MINE SAFETY DISCLOSURES

Not applicable.

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PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Listing and Holders of Record

Our common units are listed on the Nasdaq Global Select Market under the symbol “RTLR”. There was one holder of record of our common units on February 19, 2021.

Cash Distribution Policy   

At the closing of the IPO, the board of directors of our general partner adopted a policy for us to distribute cash distributions to common unitholders of record on the applicable record date of $0.25 per common unit for each quarter beginning with the quarter ending September 30, 2019. Our first distribution of $0.34, included available cash for the period from May 28, 2019, the date of the close of our IPO, through September 30, 2019. On February 13, 2020, the board of directors of our general partner revised our cash distribution policy to provide that cash distributions will be made to common unitholders of record on the applicable record date of $0.29 per common unit for each quarter ending after December 31, 2019. On October 29, 2020, the board of directors of the general partner further revised the Partnership’s cash distribution policy, reducing the quarterly distribution per common unit to $0.20 beginning with the quarter ended September 30, 2020. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

Repurchases of Equity Securities
Our common unit repurchase activity for the three months ended December 31, 2020 was as follows:
PeriodTotal Number of Units PurchasedAverage Price Paid Per UnitTotal Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(1)
(Units in thousands)
October 1, 2020 - October 31, 2020$— N/A
November 1, 2020 - November 30, 2020750$8.18 750$93,865 
December 1, 2020 - December 31, 2020900$9.56 900$85,261 
Total1,650$8.93 1,650
(1)In October 2020, our board of directors approved a common unit repurchase program to acquire up to $100.0 million of our outstanding common units through December 31, 2021. This repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time.

Recent Sales of Unregistered Securities
None.

ITEM 6.     SELECTED FINANCIAL DATA
[Reserved.]
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ITEM 7.MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto presented in this Annual Report. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See “Item 1A. Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements.”

Our Predecessor financial statements include 100% of the operations of the Operating Company, reflecting the historical ownership of these assets by Diamondback. This Annual Report includes the assets, liabilities and results of operations of our Predecessor for periods prior to May 28, 2019, the date on which we completed the IPO. Our future results of operations may not be comparable to our Predecessor’s historical results of operations.
Unless the context otherwise requires, references in this section to “we,” “our,” “us” or like terms, when used in a historical context prior to the completion of our IPO, refer to our Predecessor and, when used in a historical context following the completion of our IPO, the present tense or future tense, these terms refer to the Partnership and its subsidiaries.

Overview

We are a Delaware limited partnership formed by Diamondback to own, operate, develop and acquire midstream and energy-related infrastructure assets in the Midland and Delaware Basins of the Permian Basin, one of the most prolific oil producing areas in the world. Our assets and operations are reported in two operating business segments: (i) midstream services and (ii) real estate operations. We have elected to be treated as a corporation for U.S. federal income tax purposes.

We provide crude oil, natural gas and water-related midstream services (including water sourcing and transportation and produced water gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of December 31, 2020, our midstream infrastructure assets include 927 miles of pipeline across the Midland and Delaware Basins with approximately 275,000 Bbl/d of crude oil gathering capacity, 151,000 Mcf/d of natural gas compression capability, 170,000 Mcf/d of natural gas gathering capacity, 3.1 MMBbl/d of produced water disposal capacity and 575,000 Bbl/d of sourced water gathering capacity. In addition to our midstream infrastructure assets, we own equity interests in three long-haul crude oil pipelines that run from the Permian to the Texas Gulf Coast, and also own equity interests in third-party operated gathering systems and processing facilities supported by dedications from Diamondback. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and produced water disposal capabilities.

As of December 31, 2020, our general partner had a 100% general partner interest in us. Diamondback held no common units and beneficially owned all of our 107,815,152 outstanding Class B units, representing approximately 72% of our total units outstanding. Diamondback also owns and controls our general partner.

As of December 31, 2020, we own a 28% controlling membership interest in the Operating Company and Diamondback owns, through its ownership of the Operating Company units, a 72% economic, non-voting interest in the Operating Company. However, as required by GAAP, we consolidate 100% of the assets and operations of the Operating Company in our financial statements and reflect a non-controlling interest.

The following discussion includes a comparison of our results of operations, including changes in our operating income, and liquidity and capital resources for fiscal years 2020 and 2019. A discussion of changes in our results of operations from fiscal year 2018 to fiscal year 2019 has been omitted from this report, but may be found in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our annual report on Form 10-K for the fiscal year ended December 31, 2019, filed with the SEC on February 26, 2020 and incorporated by reference into this Annual Report.

2020 Transactions and Recent Developments

Implementation of Common Unit Repurchase Program

On October 29, 2020, the board of directors of our general partner approved a common unit repurchase program to acquire up to $100.0 million of our outstanding common units. The common unit repurchase program is authorized to extend through December 31, 2021 and we intend to purchase common units under the repurchase program opportunistically with cash
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on hand and free cash flow from operations. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of our general partner at any time. During the year ended December 31, 2020, the Partnership repurchased approximately $14.7 million of common units under this repurchase program. As of December 31, 2020, $85.3 million remained available for use to repurchase common units under the Partnership’s common unit repurchase program.

Notes Offering
On July 14, 2020, we completed an offering, which we refer to as the notes offering, of our 5.625% senior notes due 2025 in the aggregate principal amount of $500.0 million, which we refer to as the notes. We received net proceeds of approximately $489.5 million from the notes offering. We loaned the gross proceeds of the notes offering to the Operating Company, which used such proceeds to pay down borrowings under its revolving credit facility. For additional information regarding the notes offering, see “—Liquidity and Capital Resources—Indebtedness—Notes Offering” below.

Disposal Well Divestiture

On December 31, 2020, we sold five produced water disposal wells and related easements, licenses and permits for $18.7 million cash after adjustments for use of the disposal wells after the effective date. We retained ownership of the gathering system that is connected to the disposal wells. For additional information, see “Note 4—Acquisitions and Divestitures.”

COVID-19 and Collapse in Commodity Prices
On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a “pandemic.” To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Although many stay-at-home orders have expired and certain restrictions on conducting business have been lifted, the COVID-19 pandemic resulted in a widespread health crisis and a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.

In early March 2020, oil prices dropped sharply, and then continued to decline, reaching negative levels per barrel. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other exporting nations and a significant decrease in demand as a result of the ongoing COVID-19 pandemic. While OPEC members and certain other nations agreed to cut production to help reduce a portion of the excess supply in the market and improve oil prices, there is no assurance that production cuts will continue or be observed by its parties. Downward pressure on commodity prices has continued and could continue for the foreseeable future. We cannot predict if or when commodity prices will stabilize and at what levels.

We derive substantially all of our revenue from our commercial agreements with Diamondback which do not contain minimum volume commitments. The reduction of Diamondback’s drilling and development plan on the acreage dedicated to us by Diamondback directly and adversely impacts Diamondback’s demand for our midstream services. As a result of the reduction in crude oil demand caused by factors discussed above, Diamondback previously lowered its 2020 capital budgets and production guidance, curtailed near term production and reduced its rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions worsen. These actions have had and will continue to have a detrimental effect on our sourced water business line and our overall operations. Diamondback recently announced its 2021 production target of between 178,000 and 185,000 barrels of oil per day. We cannot predict the extent to which Diamondback’s business would be impacted if conditions in the energy industry were to further deteriorate nor can we estimate the impact such conditions would have on Diamondback’s ability to execute its drilling and development plan on the Dedicated Acreage or to perform under our commercial agreements.

In coordination with Diamondback’s production reductions, in March 2020, we announced a reduction in our planned 2020 capital budget of over 40%. Additionally, we lowered full year 2020 EBITDA guidance by approximately 25% at the midpoint, which assumed a 15 to 25% reduction in equity method EBITDA contributions for the year, as well as fewer volumes for our operated business due to lower activity levels. On a gross dollar basis, our reductions in planned capital expenditures on operated assets have exceeded declines in operated EBITDA in 2020. Our operations in the third and fourth quarter of 2020 stabilized after the interruption caused by the historic commodity price volatility in the second quarter of 2020. With Diamondback resuming completion activity to stem production declines, we have adjusted our operations to this new level of completion and production activity. During 2021, we expect to continue to reduce operated capital expenditures towards our
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total of approximately half of 2020 levels, representing less than a third of 2019 operated capital expenditures. Combined with our equity method joint venture build cycle nearing its end and changing from a net outflow of capital contributions to a net inflow of cash contributions, we believe that this stabilized volume outlook will present a meaningful free cash flow generation even in this depressed commodity price environment.

Operational Update

Highlights

The following are our significant operating results for the year ended December 31, 2020, as compared with the year ended December 31, 2019:

average crude oil gathering volumes were 92,056 Bbl/d, an increase of 8% year over year;
average natural gas gathering volumes were 121,637 MMBtu/d, an increase of 43% year over year;
average produced water gathering and disposal volumes were 821,543 Bbl/d, an increase of 2% year over year; and
average sourced water gathering volumes were 253,907 Bbl/d, a decrease of 39% year over year.

Pipeline Infrastructure Assets
The following tables provide information regarding our gathering, compression and transportation system as of December 31, 2020 and utilization for the year ended December 31, 2020:
(Miles)(1)
Delaware Basin Midland Basin Permian Total
Crude oil108 46 154 
Natural gas155 — 155 
Produced water269 248 517 
Sourced water27 74 101 
Total559 368 927 
(Capacity/capability)(1)
Delaware Basin Midland Basin Permian Total Utilization
Crude oil gathering (Bbl/d)210,000 65,000 275,000 36 %
Natural gas compression (Mcf/d)151,000 — 151,000 60 %
Natural gas gathering (Mcf/d)170,000 — 170,000 54 %
Produced water gathering and disposal (Bbl/d)1,310,000 1,810,000 3,120,000 26 %
Sourced water gathering (Bbl/d)120,000 455,000 575,000 44 %
(1)Does not include assets of EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

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Results of Operations for the Year Ended December 31, 2020 and 2019
    
The following table sets forth selected historical operating data for the periods indicated:
Year Ended December 31,
20202019
Operating Results:(In thousands, except operating data)
Revenues:
Revenues—related party$379,089 $409,120 
Revenues—third party31,124 24,324 
Rental income—related party7,495 4,771 
Rental income—third party5,340 7,890 
Other real estate income—related party306 379 
Other real estate income—third party551 1,189 
Total revenues423,905 447,673 
Costs and expenses:
Direct operating expenses131,393 106,311 
Cost of goods sold (exclusive of depreciation and amortization)38,370 62,856 
Real estate operating expenses2,361 2,643 
Depreciation, amortization and accretion53,123 42,336 
Impairment918 — 
General and administrative expenses16,367 12,663 
(Gain) loss on disposal of property, plant and equipment(729)1,524 
Total costs and expenses241,803 228,333 
Income (loss) from operations182,102 219,340 
Other income (expense):
Interest income (expense), net(17,287)(1,039)
Income (loss) from equity method investments(9,881)(6,329)
Total other income (expense), net(27,168)(7,368)
Net income (loss) before income taxes154,934 211,972 
Provision for (benefit from) income taxes10,229 26,253 
Net income (loss)$144,705 $185,719 
Less: Net income (loss) before initial public offering— 65,995 
Net income (loss) subsequent to initial public offering144,705 119,724 
Less: Net income (loss) attributable to non-controlling interest 110,014 90,922 
Net income (loss) attributable to Rattler Midstream LP$34,691 $28,802 
Operating Data:
Throughput(1)
Crude oil gathering (Bbl/d)92,05685,164
Natural gas gathering (MMBtu/d)121,63785,283
Produced water gathering and disposal (Bbl/d)821,543806,078
Sourced water gathering (Bbl/d)253,907415,939
(1)    Does not include volumes from the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

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Comparison of the Years Ended December 31, 2020 and 2019

Revenues

Revenues decreased by $23.8 million to $423.9 million for the year ended December 31, 2020 from $447.7 million for the year ended December 31, 2019, primarily due to a reduction in sourced water volumes due to Diamondback’s lower level of drilling and completion activity in the second through fourth quarters of 2020. This was partially offset by an increase in oil, natural gas and produced water volumes that were realized due to the build out of certain midstream assets completed in late 2019.

Direct Operating Expenses

Direct operating expenses increased by $25.1 million to $131.4 million for the year ended December 31, 2020 from $106.3 million for the year ended December 31, 2019 primarily due to increased oil, natural gas and produced water volumes that were realized due to organic volume growth on the Dedicated Acreage. In addition, we incurred certain asset maintenance and workover charges related to our produced water wells to maintain their capacity.

Cost of Goods Sold

Cost of goods sold (exclusive of depreciation and amortization) decreased by $24.5 million to $38.4 million for the year ended December 31, 2020 from $62.9 million for the year ended December 31, 2019. The decrease primarily relates to a reduction in sourced water volumes due to Diamondback’s lower level of drilling and completion activity throughout the year ended December 31, 2020.

 
Depreciation, Amortization and Accretion

Depreciation, amortization and accretion for the years ended December 31, 2020 and 2019 was $53.1 million and $42.3 million, respectively. The increase of $10.8 million was associated with the further development of existing gathering and compression, transportation and disposal systems. In addition, the midstream services segment incurred $3.0 million of accelerated depreciation related to the abandonment of certain disposal well assets. The real estate operations segment also incurred $1.1 million of accelerated amortization of in-place lease intangibles for early terminated leases.

General and Administrative Expenses

General and administrative expenses for the years ended December 31, 2020 and 2019 were $16.4 million and $12.7 million, respectively. The increase of $3.7 million was primarily due to increased shared service allocations and additional professional service fees attributable to business growth, the contribution of additional midstream assets and additional public company costs incurred.

Interest Expense, Net

Net interest expense was $17.3 million for the year ended December 31, 2020 compared to $1.0 million for the year ended December 31, 2019. The increase was primarily due to interest accrued on the senior notes issued in July 2020 of $13.9 million, as well as the timing of our entry into the credit agreement on May 28, 2019, and having a full period of borrowings resulting in interest expense of $7.6 million during 2020, net of capitalized interest of $4.2 million.

Loss from Equity Method Investments

Loss from equity method investments was $9.9 million for the year ended December 31, 2020 and was primarily related to expense associated with an impairment of OMOG’s goodwill at the partnership level in the second quarter of 2020, which was partially offset by income from our other equity method investments. For additional information, see Note 8—Equity Method Investments for further discussion of the Partnership’s equity method investments.

Provision for Income Taxes

We recorded income tax expense of $10.2 million and $26.3 million for the years ended December 31, 2020 and 2019, respectively. The change in our income tax provision was primarily due to a decrease in pre-tax income and the impact of net income attributable to the non-controlling interest for the year ended December 31, 2020. Total income tax expense for the year
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ended December 31, 2020 differed from amounts computed by applying the federal statutory tax rate to pre-tax income from continuing operations for the period primarily due to net income attributable to the non-controlling interest.

Non-GAAP Financial Measures

Adjusted EBITDA

Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure.

We define Adjusted EBITDA as net income before income taxes, interest expense, net of amount capitalized, depreciation, amortization and accretion on assets and liabilities of the Operating Company, our proportional depreciation and interest expense related to equity method investments, our proportional impairments and abandonments related to equity method investments, non-cash general and administrative expense and other non-cash transactions. The GAAP measure most directly comparable to Adjusted EBITDA is net income. However, Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance. Our computation of Adjusted EBITDA excludes some, but not all, items that affect net income because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. As a result of such differences, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

The following table presents a reconciliation of net income to Adjusted EBITDA for each of the periods indicated:
Year Ended December 31,
202020192018
(In thousands)
Reconciliation of Net Income to Adjusted EBITDA:
Net income$144,705 $185,719 $62,960 
Interest expense, net of amount capitalized17,287 1,039 — 
Depreciation, amortization and accretion53,123 42,336 25,134 
Depreciation and interest expense related to equity method investments 32,456 2,641 — 
Impairments and abandonments related to equity method investments16,543 — — 
Non-cash general and administrative9,317 5,208 — 
Other non-cash transactions189 1,528 — 
Provision for income taxes10,229 26,253 17,359 
Adjusted EBITDA283,849 264,724 $105,453 
Less: Adjusted EBITDA prior to the IPO— 100,743 
Adjusted EBITDA subsequent to the IPO283,849 163,981 
Less: Adjusted EBITDA attributable to non-controlling interest201,994 116,685 
Adjusted EBITDA attributable to Rattler Midstream LP$81,855 $47,296 

Liquidity and Capital Resources

Overview

Our sources of liquidity have included cash generated from operations, borrowings under the credit agreement and the issuance of the notes. We believe that cash generated from these sources will be sufficient to meet our short-term working capital and long-term capital expenditure requirements and to make quarterly cash distributions. We do not have any commitment from Diamondback, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us. Should we require additional capital, the prolonged volatility in the
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capital, financial and/or credit markets due to the COVID-19 pandemic, indirect effect of depressed commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.

Cash Distributions

On February 13, 2020, the board of directors of our general partner revised our cash distribution policy to provide for the Operating Company to distribute $0.29 per Operating Company unit each quarter to its unitholders (including Diamondback and the Partnership), and for the Partnership to pay, to the extent legally available, cash distributions of $0.29 per common unit to common unitholders of record on the applicable record date within 65 days after the end of each quarter beginning with the quarter ended December 31, 2019. On October 29, 2020, the board of directors of our general partner further revised our cash distribution policy, reducing the quarterly distribution per Operating Company unit and common unit to $0.20 beginning with the quarter ended September 30, 2020.
We do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time and from time to time. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly basis or other basis.
On February 17, 2021, the board of directors of the general partner approved a cash distribution for the fourth quarter of 2020 of $0.20 per common unit, payable on March 15, 2021, to common unitholders of record at the close of business on March 8, 2021.
Cash Flows

The following table presents our cash flows for the periods indicated:
 Year Ended December 31,
 20202019
(In thousands)
Net cash provided by (used in) operating activities$229,899 $218,193 
Net cash provided by (used in) investing activities(180,809)(578,369)
Net cash provided by (used in) financing activities(35,796)362,245 
Net increase (decrease) in cash$13,294 $2,069 
Operating Activities
Net cash provided by operating activities increased by $11.7 million during the year ended December 31, 2020 compared to the year ended December 31, 2019. The increase was primarily due to changes in working capital, which include the timing of collections on accounts receivable, and a decline in accrued capital expenditures resulting from the reduction in our capital expenditures budget in 2020.
Investing Activities

Net cash used in investing activities was $180.8 million and $578.4 million during the years ended December 31, 2020 and 2019, respectively, and, in both years, was primarily related to additions to property, plant and equipment and contributions to our equity method investments, which were partially offset by distributions received from our Gray Oak and OMOG equity method investments. See “Item 8. Financial Statements and Supplementary Data—Note 8. Equity Method Investments.”

Financing Activities

Net cash used in financing activities was $35.8 million during the year ended December 31, 2020, primarily related to $345.0 million of payments on the credit facility, net of borrowings under the credit facility, and distributions to our unitholders of $162.4 million which were largely offset by proceeds from the notes offering of $500.0 million.

Net cash used in financing activities was $362.2 million during the year ended December 31, 2019, primarily related to net proceeds of $719.4 million from our IPO of common units and net credit facility borrowings of $424.0 million, partially offset by distributions to our unitholders of $778.1 million during 2019.
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Capital Contributions and Capital Expenditures

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. However, with respect to capital expenditures incurred for acquisitions or capital improvements, we have some discretion and control. In a time of reduced operational activity, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to factors both within and outside our control.

For the year ended December 31, 2020, our total capital expenditures were $136.8 million, of which $111.2 million was related to produced water disposal assets, $7.9 million was related to crude oil gathering assets, $8.9 million was related to natural gas gathering assets, $8.2 million was related to sourced water assets and $0.6 million was related to real estate assets.

For the year ended December 31, 2019, the total capital contributions by Diamondback to the Predecessor were $456.1 million, of which $9.2 million related to an office building located in Midland Texas, $18.1 million related to land, $9.4 million related to sourced water assets, $228.3 million related to produced water disposal assets, $35.8 million related to crude oil assets, $149.5 million related to the equity method investments in the EPIC and Gray Oak joint ventures, $31.1 million related to elimination of current and deferred liabilities, and $(25.3) million in additional assets and liabilities, net, related to operations. During this period, the Operating Company made capital expenditures of $241.8 million, comprised of $152.8 million related to produced water disposal assets, $27.1 million related to crude oil gathering assets, $38.1 million related to natural gas gathering assets and $23.8 million related to sourced water assets.

We estimate that our total capital expenditures related to midstream assets for 2021 will be between $60 million and $80 million. Our estimated capital expenditures do not include our anticipated total capital commitments related to our equity method investments of approximately $10 million to 20 million. We also estimate $35 million to $45 million of distributions related to our equity method investments. However, this range could decrease due to the continued impact, either directly or indirectly, of the COVID-19 pandemic or depressed crude oil prices on our business.

Based upon current expectations for 2021, we believe that our cash flows from operations, cash on hand and borrowings under our revolving credit facility will be sufficient to fund our operations and anticipated future capital commitments through the 12-month period following the filing of this report.

Indebtedness

The Operating Company’s Revolving Credit Facility

The Partnership, as parent, and the Operating Company, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks, including Wells Fargo Bank, National Association, as lenders party thereto, which we refer to as the credit agreement.
The Operating Company’s credit agreement provides for a revolving credit facility in the maximum credit amount of $600.0 million, which is expandable to $1.0 billion upon our election, subject to obtaining additional lender commitments and satisfaction of customary conditions. In July 2020, we loaned the gross proceeds from the notes offering discussed below to the Operating Company, which used such proceeds to pay down borrowings under its revolving credit facility. As of December 31, 2020, there was $79.0 million of outstanding borrowings, and $521.0 million available for future borrowings, under the credit agreement.

On November 2, 2020, the Partnership and the Operating Company entered into a second amendment to the Operating Company’s credit agreement with Wells Fargo, as the administrative agent, and the lenders party thereto. The second amendment permits us to conduct common unit repurchases in connection with the common unit repurchase program discussed above under “—2020 Transactions and Recent Developments—Implementation of Common Unit Repurchase Program.”
As of December 31, 2020, the Operating Company was in compliance with all financial maintenance covenants under the credit agreement.
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For additional information regarding the revolving credit facility, see Note 9—Debt included in the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report.

Notes Offering

On July 14, 2020, we completed an offering of our 5.625% senior notes due 2025 in the aggregate principal amount of $500.0 million. We received net proceeds of approximately $489.5 million from the notes offering. We loaned the gross proceeds of the notes offering to the Operating Company, which used such proceeds to repay then outstanding borrowings under its credit agreement.

The notes were issued under an indenture, dated as of July 14, 2020, among the Partnership, as issuer, the Operating Company, Tall Towers, Rattler OMOG LLC and Rattler Ajax Processing LLC, our subsidiaries, as guarantors, and Wells Fargo Bank, National Association, as trustee, which we refer to as the indenture. Pursuant to the indenture, interest on the notes accrues at a rate of 5.625% per annum on the outstanding principal amount thereof from July 14, 2020, payable semi-annually on January 15 and July 15 of each year, commencing on January 15, 2021. The notes will mature on July 15, 2025.

 
Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2020:
Payments Due by Period
Total Less than 1 year1-3 years3-5 yearsMore than 5 years
(In thousands)
Credit agreement(1)
$79,000 $— $— $79,000 $— 
Senior notes500,000 — — 500,000 — 
Interest expense related to the senior notes(2)
140,625 28,125 56,250 56,250 — 
Operating leases (3)
595 595 — — — 
Volume commitment agreement(4)
55,663 4,563 9,126 9,124 32,850 
Total$775,883 $33,283 $65,376 $644,374 $32,850 
(1)    Includes the outstanding principal amount under the revolving credit facility. The table does not include commitment fees, interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.
(2)    Interest represents the scheduled cash payments on the notes.
(3)    Operating lease obligations represent future commitments for equipment leases.
(4)    Volume commitment agreement represents a commitment to deliver contracted volumes of produced water for disposal services to a third party under an agreement which has a term of fourteen years.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP.

Certain amounts included in or affecting our consolidated financial statements and related disclosures must be estimated by our management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the consolidated financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities and our disclosure of contingent assets and liabilities at the date of the consolidated financial statements. Critical accounting policies cover accounting estimates that are inherently uncertain because the future resolution of such matters is unknown and actual results could differ from those estimates.

We evaluate these estimates on an ongoing basis, using historical experience, consultation with experts and other methods we consider reasonable in the particular circumstances. Any effects on our business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include (i) depreciation of our long-lived assets, including intangible lease assets, (ii) impairment of long-lived assets, (iii) accounting for equity method investments, (iv) asset retirement obligations and (v) estimate of income taxes.

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Below, we have provided expanded discussion of our most critical accounting estimates, assumptions, judgments and uncertainties that are inherent in our application of GAAP.
 

Property, Plant and Equipment Depreciation

Property, plant and equipment is recorded at cost upon acquisition. Expenditures which extend the useful lives of existing property, plant and equipment are capitalized. When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any gain or loss on disposition is recognized in the consolidated statement of operations. The historical cost and any subsequent capitalized expenditures for our property, plant and equipment is depreciated using the straight-line method over the useful lives of the assets ranging from ten to thirty years.

The determination of estimated useful lives is a significant element in calculating depreciation, amortization and accretion on our property, plant and equipment. If the useful lives of assets were found to be shorter than originally estimated, depreciation, amortization and accretion charges would be accelerated.

Impairment of Long-Lived Assets

Whenever triggering events occur which indicate we may not be able to recover the carrying amount of our long-lived assets we evaluate whether our long-lived assets have been impaired. Impairment exists when the carrying amount of an asset exceeds estimates of the undiscounted cash flows expected to result from the use and eventual disposition of the asset. Our impairment analysis requires management to apply judgment in grouping our assets appropriately, identifying impairment indicators, and estimating future cash flows for these asset groupings. Our estimates of future undiscounted cash flows take into account possible outcomes and probabilities of their occurrence when alternative courses of action to recover the carrying amount of a long-lived asset are under consideration. If we determine the carrying amount of the long-lived asset is not recoverable, the impairment loss is measured as the excess of the asset’s carrying amount over its estimated fair value. The asset’s carrying value is then reduced to its estimated fair value with an offsetting charge to impairment expense.

Fair value represents the estimated price between market participants to sell an asset in the principal or most advantageous market for the asset, based on assumptions a market participant would make. When indicators of impairment are present, we assess the fair value of our long-lived assets using commonly accepted techniques such as internally developed forecasts of the assets future profitability and cash flow, and may use more than one source in making such assessments. The factors used to determine fair value rely on management’s judgment and expertise. A reduction of the carrying value of fixed assets would represent a Level 3 fair value measurement.

If actual results are not consistent with our assumptions and estimates or our assumptions and estimates change due to new information, we may be exposed to additional impairment charges. Prolonged periods of lower commodity prices may adversely affect our estimate of future operating results through lower throughput volumes on our assets and less demand for our sourced water and produced water services, which could result in future impairment charges due to the potential impact on our operations and cash flows.

Equity Method Investments

An investment of less than 50% in an investee over which the Partnership exercises significant influence but does not have control is accounted for using the equity method. Additionally, an investment of greater than 50% in an investee over which the Partnership does not exercise significant influence or have control is also accounted for using the equity method. Under the equity method, the Partnership’s share of the investee’s earnings or loss is recognized in the statement of operations. The Partnership’s proportionate share of the income or loss from equity method investments is recognized on a one-month lag for all equity method investments. The Partnership reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such a loss has occurred, the Partnership recognizes an impairment provision.

Judgment regarding the level of influence over each equity method investment includes considering key factors such as ownership interest, representation on the board of directors, participation in policy-making decisions, material intercompany transactions and extent of ownership by an investor in relation to the concentration of other shareholdings. Control typically exists when an entity holds a greater than 50% ownership interest in an investee, but is also determined by other factors such as contract, operating control, management influence and economic interest. Additionally, an investment in a limited liability company that maintains a specific ownership account for each investor shall be viewed as similar to an investment in a limited partnership for purposes of determining whether a noncontrolling investment shall be accounted for using the cost method or the equity method. Investments of greater than 3% to 5% are considered more than minor and, therefore, should be accounted
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for using the equity method. For investments where the Partnership has less than a 20% ownership interest, the investment is accounted for as an equity method investment as the Partnership has the ability to exercise significant influence.

Asset Retirement Obligations

Our asset retirement obligations, or ARO, consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our infrastructure assets. We recognize the fair value of a liability for an ARO in the period in which it is incurred, when we have an existing legal obligation associated with the retirement of our infrastructure assets and the obligation can reasonably be estimated. The associated asset retirement cost is capitalized as part of the carrying cost of the infrastructure asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding factors such as: the credit-adjusted risk-free rate to be used, inflation rates and estimated probabilities, amounts and timing of settlements. In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Revisions also result in increases or decreases in the carrying cost of the asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through depreciation.

Income Taxes

On May 24, 2019, we elected to be treated as a corporation for U.S. federal income tax purposes. The amount of income taxes we record requires interpretations of complex rules and regulations of federal, state, provincial and foreign tax jurisdictions.
We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (i) temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized after considering all positive and negative evidence available concerning the realizability of our deferred tax assets.

Recent Accounting Pronouncements
See Note 2. Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report for a full listing of our significant accounting policies.

Off-Balance Sheet Arrangements
None.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Commodity Price Risk

We currently generate the majority of our revenues pursuant to fee-based agreements with Diamondback under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flow have little direct exposure to commodity price risk. However, Diamondback and our other customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.

We may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and natural gas liquids prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.

Credit Risk

We are subject to counterparty credit risk related to our midstream commercial contracts, lease agreements and joint venture receivables. We derive substantially all of our revenue from our commercial agreements with Diamondback. As a result, we are directly affected by changes to Diamondback’s business related to operational and business risks or otherwise. We cannot predict the extent to which Diamondback’s business would be impacted if conditions in the energy industry were to deteriorate, nor can we estimate the impact such conditions would have on Diamondback’s ability to execute its drilling and development program or to perform under our agreements. While we monitor the creditworthiness of purchasers, lessees and joint venture partners with which we conduct business, we are unable to predict sudden changes in solvency of these counterparties and may be exposed to associated risks. Non-performance by a counterparty could result in significant financial losses.
Interest Rate Risk

We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s credit agreement. The terms of the credit agreement provide for interest at a rate elected by the Operating Company that is based on the prime rate or LIBOR, in each case plus margins ranging from 0.250% to 1.250% for prime-based loans and 1.250% to 2.250% per annum for LIBOR loans, in each case depending on the Consolidated Total Leverage Ratio (as defined in the credit agreement). The Operating Company is obligated to pay a quarterly commitment fee ranging from 0.250% to 0.375% per annum on the unused portion of the commitment, which fee is also dependent on the Consolidated Total Leverage Ratio.
As of December 31, 2020, we had $79.0 million of outstanding borrowings and $521.0 million available for future borrowings under the credit agreement. The weighted average interest rate on borrowings under the credit agreement was 2.10% as of December 31, 2020.

 
ITEM 8.     FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The information required by this Item appears beginning on page F-1 of this report.

ITEM 9.     CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

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ITEM 9A.          CONTROLS AND PROCEDURES

Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and Chief Financial Officer of our general partner, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our general partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

As of December 31, 2020, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our general partner have concluded that as of December 31, 2020, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of our general partner is responsible for establishing and maintaining adequate internal control over financial reporting of the Partnership. The Partnership’s internal control over financial reporting is a process designed under the supervision of the Chief Executive Officer and Chief Financial Officer of our general partner to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Partnership’s financial statements for external purposes in accordance with generally accepted accounting principles.

Management conducted an evaluation of the effectiveness of the Partnership’s internal control over financial reporting based on the framework in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on its evaluation under the framework in the 2013 Internal Control-Integrated Framework, management did not identify any material weaknesses in the Partnership’s internal control over financial reporting and determined that the Partnership maintained effective internal control over financial reporting as of December 31, 2020.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Attestation Report of the Registered Public Accounting Firm. This Annual Report does not include an attestation report of the company’s registered public accounting firm due to the SEC rules applicable to “emerging growth companies.” We will remain an “emerging growth company,” as defined in Rule 12b-2 of the Exchange Act, for up to five full fiscal years following the IPO, although we will lose such status sooner if we have more than $1.07 billion of revenues in a fiscal year, become a large accelerated filer or issue more than $1.07 billion of non-convertible debt cumulatively over a three-year period.

ITEM 9B.     OTHER INFORMATION

None.
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PART III

ITEM 10.     DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Management of Rattler Midstream LP

We are managed and operated by the board of directors and the executive officers of our general partner.

Diamondback owns all of the membership interests in our general partner. As a result of owning our general partner, Diamondback has the right to appoint all members of the board of directors of our general partner, including the independent directors. Our common unitholders are not entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. Our general partner owes certain duties to our common unitholders as well as a fiduciary duty to its owner.

The executive officers of our general partner manage the day-to-day affairs of our business. All of the executive officers of our general partner also serve as executive officers of Diamondback and the general partner of Viper. Our executive officers listed below allocate their time between managing our business and the businesses of Diamondback and Viper. Our executive officers intend, however, to devote as much time as is necessary for the proper conduct of our business.

 
Executive Officers and Directors of Our General Partner

The following table presents information regarding the executive officers and directors of our general partner as of January 31, 2021. Directors hold office until their successors have been elected or qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers serve at the discretion of the board of directors of our general partner. There are no family relationships among any of our general partner’s directors or executive officers.
NameAgePosition With Our General Partner
Travis D. Stice59Chief Executive Officer and Director
Kaes Van't Hof34President and Director
Teresa L. Dick51Chief Financial Officer, Executive Vice President and Assistant Secretary
Matt Zmigrosky42Executive Vice President, General Counsel and Secretary
Steven E. West60Chairman of the Board
Laurie H. Argo48Director
Arturo Vivar58Director

Travis D. Stice. Mr. Stice has served as Chief Executive Officer and a director of our general partner since July 2018. He has served as Chief Executive Officer of Diamondback since January 2012 and as a director since November 2012. Mr. Stice has also served as the Chief Executive Officer and a director of the general partner of Viper since February 2014. Prior to his current positions with our general partner, Diamondback and Viper’s general partner, he served as Diamondback’s President and Chief Operating Officer from April 2011 to January 2012. From November 2010 to April 2011, Mr. Stice served as a Production Manager of Apache Corporation, an oil and gas exploration company. Mr. Stice served as a Vice President of Laredo Petroleum Holdings, Inc., an oil and gas exploration and production company, from September 2008 to September 2010 and as a Development Manager of ConocoPhillips/Burlington Resources Mid-Continent Business Unit, an oil and gas exploration company, from April 2006 until August 2008. Prior to that, Mr. Stice held a series of positions of increasing responsibilities at Burlington Resources, most recently as a General Manager, Engineering, Operations and Business Reporting of its Mid-Continent Division from January 2001 until Burlington Resources’ acquisition by ConocoPhillips in March 2006. He started his career with Mobil Oil in 1985. Mr. Stice has over 35 years of industry experience in production operations, reservoir engineering, production engineering and unconventional oil and gas exploration and over 20 years of management experience. Mr. Stice graduated from Texas A&M University with a Bachelor of Science degree in Petroleum Engineering. Mr. Stice is a registered engineer in the State of Texas, and is a 35-year member of the Society of Petroleum Engineers.

We believe Mr. Stice’s expertise and extensive industry and executive management experience, including at Diamondback and Viper, make him a valuable asset to the board of directors of our general partner.

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Kaes Van’t Hof. Mr. Van’t Hof has served as President and a director of our general partner since July 2018. He has served as Diamondback’s Chief Financial Officer and Executive Vice President of Business Development since March 2019 after joining Diamondback in July 2016 as Vice President and serving as its Senior Vice President-Strategy and Corporate Development from February 2017 to February 2019. Mr. Van’t Hof has also served as the President of the general partner of Viper since March 2017. Prior to his positions with our general partner, Diamondback and Viper’s general partner, Mr. Van’t Hof served as Chief Executive Officer for Bison Drilling and Field Services from September 2012 to June 2016. From August 2011 to August 2012, Mr. Van’t Hof was an analyst for Wexford Capital, LP responsible for developing operating models and business plans, including for Diamondback’s initial public offering, and before that worked for the Investment Banking-Financial Institutions Group of Citigroup Global Markets, Inc. from February 2010 to August 2011. Mr. Van’t Hof was a professional tennis player from May 2008 to January 2010. Mr. Van’t Hof received a Bachelor of Science degree in Accounting and Business Administration from the University of Southern California.
 

We believe Mr. Van’t Hof’s background in finance, accounting and private equity energy investments, as well as his expertise and executive management experience, make him a valuable asset to the board of directors of our general partner.

Teresa L. Dick. Ms. Dick has served as Chief Financial Officer, Executive Vice President and Assistant Secretary of our general partner since July 2018. She has also served as Diamondback’s Executive Vice President and Chief Accounting Officer since March 2019. Ms. Dick served as Diamondback’s Executive Vice President and Chief Financial Officer from February 2017 to February 2019, as its Assistant Secretary since October 2012, as its Chief Financial Officer and Senior Vice President from November 2009 to February 2017 and as its Corporate Controller from November 2007 until November 2009. Ms. Dick has also served as Chief Financial Officer, Executive Vice President and Assistant Secretary of the general partner of Viper since February 2017 and served as its Chief Financial Officer, Senior Vice President and Assistant Secretary from February 2014 to February 2017. From June 2006 to November 2007, Ms. Dick held a key management position as the Controller/Tax Director at Hiland Partners, a publicly-traded midstream energy MLP. Ms. Dick has over 20 years of accounting experience, including over eight years of public company experience in both audit and tax areas. Ms. Dick received her Bachelor of Business Administration degree in Accounting from the University of Northern Colorado. Ms. Dick is a certified public accountant and a member of the American Institute of CPAs and the Council of Petroleum Accountants Societies.

Matt Zmigrosky. Mr. Zmigrosky has served as Executive Vice President, General Counsel and Secretary of our general partner since February 2019. Since February 2019, he has also served as Executive Vice President, General Counsel and Secretary of both Diamondback and the general partner of Viper. Prior to joining Diamondback and Viper’s general partner, Mr. Zmigrosky was in the private practice of law for over 15 years. From October 2012 until January 2019, Mr. Zmigrosky was a partner at Akin Gump Strauss Hauer & Feld LLP, an international law firm, where he worked extensively with Diamondback and its subsidiaries. Mr. Zmigrosky received a Bachelor of Science in Management degree in finance from Tulane University and a Juris Doctorate degree from Southern Methodist University Dedman School of Law.

Steven E. West. Mr. West has served as the Chairman of the Board of our general partner since May 2019, and as a director and Chairman of the general partner of Viper since February 2014. Mr. West has also served as a director of Diamondback since December 2011 and as its Chairman of the Board since October 2012. He served as Diamondback’s Chief Executive Officer from January 2009 to December 2011. From January 2011 until December 2016, Mr. West was a partner at Wexford Capital LP, focusing on Wexford’s private equity energy investments. From August 2006 until December 2010, Mr. West served as senior portfolio advisor at Wexford. From August 2003 until August 2006, he was the Chief Financial Officer of Sunterra Corporation, a former Wexford portfolio company. From December 1993 until July 2003, Mr. West held senior financial positions at Coast Asset Management and IndyMac Bank. Prior to that, he worked at First Nationwide Bank, Lehman Brothers and Peat Marwick Mitchell & Co., the predecessor of KPMG LLP. Mr. West earned a Bachelor of Science degree in Accounting from California State University, Chico.

We believe that Mr. West’s background in finance, accounting and private equity energy investments, as well as his executive management skills developed as part of his career with Wexford, its portfolio companies and other financial institutions, qualify him to serve on the board of directors of our general partner. In particular, we believe Mr. West’s strengths in the following core competencies provide value to our general partner’s board of directors: corporate governance; finance/capital markets; financial reporting/accounting experience; industry background; executive experience; executive compensation; and risk management.

Laurie H. Argo. Ms. Argo is a director of our general partner. Since August 2018, Ms. Argo has served as a director and member of the audit committee of EVRAZ plc, a multinational, vertically integrated steel making and mining company. From January 2015 until September 2017, Ms. Argo served as Senior Vice President of Enterprise Products Holdings LLC, the general partner of Enterprise Products Partners L.P., a midstream natural gas and crude oil pipeline company. From January 2014 to January 2015, Ms. Argo was Vice President, NGL Fractionation, Storage and Unregulated Pipelines of Enterprise
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Products Partners L.P. From October 2014 to February 2015, Ms. Argo was President and Chief Executive Officer of OTLP GP, LLC, the general partner of Oiltanking Partners, L.P. and an affiliate of Enterprise Products Partners L.P. From 2005 to January 2014, Ms. Argo held various positions in the NGL and Natural Gas Processing businesses for Enterprise Products Partners L.P., where her responsibilities included the commercial and financial management of four joint venture companies. From 2001 to 2004, Ms. Argo worked for San Diego Gas and Electric Company in San Diego, California, and PG&E Gas Transmission, a subsidiary of PG&E Corporation, in Houston, Texas, from 1997 to 2000. Ms. Argo earned a Master of Business Administration from National University in La Jolla, California and graduated from St. Edward’s University in Austin, Texas with a degree in Accounting. Ms. Argo has over 20 years of experience in the energy industry.

We believe Ms. Argo’s extensive experience in the oil and gas industry, including the midstream sector, as well as her previous board and audit committee experience, qualify her for service on the board of directors of our general partner.

Arturo Vivar. Mr. Vivar is a director of our general partner. Mr. Vivar has served as the Chief Executive Officer of Monterra Energy Holdings LLC, a midstream development company, since December 2014. Mr. Vivar was also a founder and served as the Chief Financial Officer of Rangeland Energy, LLC, a midstream development company, from November 2009 to March 2013. Prior to that, Mr. Vivar served as the Vice President of Business Development at WesPac Energy, LLC from July 2004 to February 2009, where he focused on developing energy infrastructure, hedging and risk management. Mr. Vivar has more than 25 years of experience in the energy industry. Mr. Vivar received his Bachelor of Science degree in Civil Engineering from Cal Polytechnic University and earned his Master of Business Administration degree from Stanford University.

We believe Mr. Vivar’s strong background and diverse experience in the energy industry, especially the midstream sector, qualify him for service on the board of directors of our general partner.

Director Independence

The board of directors of our general partner has five directors, three of whom are independent as defined under the independence standards established by Nasdaq and the Exchange Act. Steven E. West, Laurie H. Argo and Arturo Vivar serve as the independent members of the board of directors of our general partner. Although a majority of the board of directors of our general partner is independent, Nasdaq does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by Nasdaq and the Exchange Act.

Board Leadership Structure and Role in Risk Oversight

Leadership of our general partner’s board of directors is vested in the Chairman of the Board. Steven E. West serves as the Chairman of the Board of our general partner and as Chairman of the Board of Diamondback. Our general partner’s board of directors has determined that the combined roles of Chairman of the Board of directors of our general partner and Chairman of the Board of Diamondback allows the board of directors to take advantage of the leadership skills of Mr. West and that Mr. West’s in-depth knowledge of, and experience in, our business, history, structure and organization facilitates timely communications between the board of directors of Diamondback and the board of directors of our general partner.

As a partnership engaged in the oil and natural gas industry, we face a number of risks, including risks associated with supply of and demand for oil and natural gas, volatility of oil and natural gas prices, exploring for, developing, producing and delivering oil and natural gas, declining production, environmental and other government regulations and taxes, weather conditions that can affect oil and natural gas operations over a wide area, adequacy of our insurance coverage, political instability or armed conflict in oil and natural gas producing regions and the overall economic environment. Management is responsible for the day-to-day management of risks we face as a partnership, while the board of directors of our general partner, as a whole and through its committees, has responsibility for the oversight of risk management. In its risk oversight role, the board of directors of our general partner has the responsibility to satisfy itself that the risk management processes designed and implemented by management are adequate and functioning as designed.

The board of directors of our general partner believes that full and open communication between management and the board is essential for effective risk management and oversight. The Chairman of the board of directors of our general partner meets regularly with the Chief Executive Officer and the Chief Financial Officer to discuss strategy and risks facing us. Executive officers may attend the board meetings of our general partner and are available to address any questions or concerns raised by the board on risk management-related and any other matters. Other members of our management team periodically
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attend the board meetings or are otherwise available to confer with the board to the extent their expertise is required to address risk management matters. Periodically, the board of directors of our general partner receives presentations from senior management on strategic matters involving our operations. During such meetings, the board also discusses strategies, key challenges, and risks and opportunities for us with senior management.

While the board of directors of our general partner is ultimately responsible for our risk oversight, its two committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists the board in fulfilling its oversight responsibilities with respect to risk management in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements, and discusses policies with respect to risk assessment and risk management. The conflicts committee assists the board in fulfilling its oversight responsibilities with respect to specific matters that the board believes may involve conflicts of interest.

Meetings of the Board of Directors

    During 2020, the board of directors of our general partner met six times. Each director attended 100% of the meetings of the board and the committees of the board on which he or she served that occurred during 2020.

Communications with Directors

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: c/o Secretary, Rattler Midstream LP, 500 West Texas, Suite 1200, Midland, Texas. Communications are distributed to the board of directors, committee of the board of directors, or director as appropriate, depending on the facts and circumstances outlined in the communication. Commercial solicitations or communications will not be forwarded.

Committees of the Board of Directors

The board of directors of our general partner has an audit committee and a conflicts committee. We do not have a compensation committee or a nominating and corporate governance committee. Rather, the board of directors of our general partner has authority over compensation matters and nominating and corporate governance matters.

 
Audit Committee

The audit committee assists the board of directors in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to retain and terminate our independent registered public accounting firm, approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm, and pre-approve any non-audit services and tax services to be rendered by our independent registered public accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary. The audit committee has adopted a charter, which is available on our website under the “corporate governance” section at https://www.rattlermidstream.com/investor-relations.

Steven E. West, Laurie H. Argo and Arturo Vivar currently serve on the audit committee. The board of directors of our general partner has determined each of Steven E. West, Laurie H. Argo, and Arturo Vivar meet the independence and experience standards established by the Nasdaq and the Exchange Act and that Mr. West is an “audit committee financial expert” as defined under SEC rules.

Conflicts Committee
Our conflicts committee reviews specific matters that the board believes may involve conflicts of interest and determines to submit to the conflicts committee for review. The conflicts committee determines if the resolution of the conflict of interest is in our best interest. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, including Diamondback, and must meet the independence standards established by Nasdaq and the Exchange Act to serve on an audit committee of a board of directors, along with other requirements in our partnership agreement. Any matters approved by the conflicts committee will be conclusively deemed to be approved by us and all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders. Laurie H. Argo and Arturo Vivar are the members of the conflicts committee.
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Corporate Governance

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics, or Code of Ethics, that applies to all employees, including executive officers, and directors of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. We have also made the Code of Ethics available on our website under the “Corporate Governance” section at https://www.rattlermidstream.com/investor-relations.

Reimbursement of Expenses of our General Partner

Our partnership agreement requires us to reimburse our general partner and its affiliates, including Diamondback, for all expenses they incur and payments they make on our behalf in connection with operating our business. Our partnership agreement does not set a limit on the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner by its affiliates. Our partnership agreement provides that our general partner will determine the expenses that are allocable to us. In addition, at the closing of our IPO, we and our general partner entered into the services and secondment agreement with Diamondback.

ITEM 11.     EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

As is commonly the case for publicly traded limited partnerships, we have no officers. Our general partner has the sole responsibility for conducting our business and for managing our operations, and its board of directors and executive officers make decisions on our behalf. Our general partner’s executive officers are employed and compensated by Diamondback or a subsidiary of Diamondback. All of our general partner’s executive officers that are responsible for managing our day-to-day affairs are also current executive officers of Diamondback.

All of the executive officers of our general partner have responsibilities to us, Diamondback and Viper, and the executive officers of our general partner allocate their time between managing our business and managing the businesses of Diamondback and Viper. Since all of these executive officers are employed by Diamondback or one of its subsidiaries, the responsibility and authority for compensation-related decisions for these executive officers resides with the compensation committee of the board of directors of Diamondback. Diamondback has the ultimate decision-making authority with respect to the total compensation of the executive officers that are employed by Diamondback including, subject to the terms of our partnership agreement and the operational service and secondment agreement, the portion of that compensation that is allocated to us pursuant to Diamondback’s allocation methodology. Any such compensation decisions are not subject to any approvals by the board of directors of our general partner or any committees thereof. However, all determinations with respect to awards (as defined below) that are made to our general partner’s executive officers, key employees, and independent directors under our LTIP (as defined below) are made by the board of directors of our general partner or a committee thereof that may be established for such purpose.

The executive officers of our general partner, as well as the employees of Diamondback who provide services to us, may participate in employee benefit plans and arrangements sponsored by Diamondback, including plans that may be established in the future. Certain of our general partner’s executive officers and employees and certain employees of Diamondback who provide services to us currently hold grants under Diamondback’s and Viper’s equity incentive plans. Except with respect to any awards that may be granted under the LTIP, the executive officers of our general partner do not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement and the operational service and secondment agreement, we reimburse Diamondback for compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Although we bear an allocated portion of Diamondback’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we have no control over such costs and do not establish nor direct the compensation policies or practices of Diamondback. Except with respect to awards granted under the LTIP, compensation paid or awarded by us in 2020 consisted only of the portion of compensation paid by Diamondback that is allocated to us and our general partner pursuant to Diamondback’s allocation methodology and subject to the terms of our partnership agreement.
 

A full discussion of the compensation programs for Diamondback’s executive officers and the policies and philosophy of the compensation committee of Diamondback’s board of directors will be set forth in Diamondback’s 2021 proxy statement under the heading “Compensation Discussion and Analysis.” Specifically, compensation paid directly by us through our LTIP or indirectly by us through reimbursement pursuant to our partnership agreement will be included in the amounts set forth in
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certain of the tables included in Diamondback’s 2021 proxy statement, with awards outstanding pursuant to our LTIP separately identified.

Long-Term Incentive Plan

To incentivize our management and directors to continue to grow our business, the board of directors of our general partner adopted a long-term incentive plan, or the LTIP, for employees, officers, consultants and directors of our general partner and any of its affiliates, including Diamondback, who perform services for us.

The purpose of the LTIP is to provide a means to attract and retain individuals who are essential to our growth and profitability and to encourage them to devote their best efforts to advancing our business by affording such individuals a means to acquire and maintain ownership of awards, the value of which is tied to the performance of our common units. The LTIP provides for the grant of unit options, unit appreciation rights, restricted units, unit awards, phantom units, distribution equivalent rights, cash awards, performance awards, other unit-based awards and substitute awards, or, collectively, awards. These awards are intended to align the interests of employees, officers, consultants and directors with those of our common unitholders and to give such individuals the opportunity to share in our long-term performance. Any awards that are made under the LTIP will be approved by the board of directors of our general partner or a committee thereof that may be established for such purpose. We will be responsible for the cost of awards granted under the LTIP.

During 2020, our general partner made grants under the LTIP of phantom units to the non-employee directors of our general partner (see “–Director Compensation” below for information regarding those awards). In addition, on May 28, 2019, our general partner granted 114,286 and 1,142,857 phantom units, respectively, to Messrs. Stice and Van’t Hof under the LTIP, with each such grant vesting in five equal installments beginning on May 28, 2020.
 

Administration

The LTIP is administered by the board of directors of our general partner pursuant to its terms and all applicable state, federal, or other rules or laws. The board of directors of our general partner has the power to determine to whom and when awards will be granted, determine the amount of awards (measured in cash or common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.

Amendment or Termination of Long-Term Incentive Plan

The plan administrator of the LTIP, at its discretion, may terminate the LTIP at any time with respect to the common units for which a grant has not previously been made. The plan administrator of the LTIP also has the right to alter or amend the LTIP or any part of it from time to time or to amend any outstanding award made under the LTIP, provided that no change in any outstanding award may be made that would materially reduce the vested rights or benefits of the participant without the consent of the affected participant or result in additional taxation to the participant under Section 409A of the Internal Revenue Code of 1986, as amended, or the Code.

Change of Control

Upon a “change of control” (as defined in the LTIP), the plan administrator may, in its discretion, (i) remove any forfeiture restrictions applicable to an award, (ii) accelerate the time of exercisability or vesting of an award, (iii) require awards to be surrendered in exchange for a cash payment, (iv) cancel unvested awards without payment or (v) make adjustments to awards as the plan administrator deems appropriate to reflect the change in control. The LTIP provides the plan administrator discretion to determine whether or not vesting of awards will accelerate in connection with a change in control and what conditions will apply to acceleration, such as whether acceleration will be single trigger or double trigger. The intent is to give the plan administrator flexibility to determine the appropriate form of incentive that will motivate and retain employees and be in the best interest of equity holders.


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Termination of Employment or Service

The consequences of the termination of a participant’s employment, consulting arrangement or membership on the board of directors of our general partner will be determined by the plan administrator in the terms of the relevant award agreement.

Compensation Report

Neither we nor the board of directors of our general partner has a compensation committee. Additionally, as an emerging growth company, we are not required to include a Compensation Discussion and Analysis section in this Annual Report. However, the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above. Based on this review and discussion, the board of directors of our general partner has approved the Compensation Discussion and Analysis for inclusion in this Annual Report.
The Board of Directors of Rattler Midstream GP LLC
Travis D. Stice
Kaes Van't Hof
Steven E. West
Laurie H. Argo
Arturo Vivar

Director Compensation

The executive officers or employees of our general partner or of Diamondback who also serve as directors of our general partner do not receive additional compensation for their service as a director of our general partner. Directors of our general partner who are not executive officers or employees of our general partner or of Diamondback receive compensation as “non-employee directors” as set by our general partner’s board of directors.

Each non-employee director receives a compensation package that consists of an annual cash retainer of $60,000 plus an additional annual payment of $15,000 for the chairperson and $10,000 for each other member of the audit committee and $10,000 for the chairperson and $5,000 for each other member of each other committee. Each non-employee director is eligible to participate in the LTIP as described above and may receive grants of equity-based awards from time to time for so long as he or she serves as a director. Our directors are also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or its committees. The maximum value of the annual cash and equity compensation that any non-employee director may receive will not exceed $350,000.

Each member of the board of directors of our general partner is indemnified for his or her actions associated with being a director to the fullest extent permitted under Delaware law.

The following table sets forth the aggregate dollar amount of all fees paid to each of the non-employee directors of our general partner during 2020 for their services on the board:
NameFees Earned or Paid in cash(a)Unit Awards(b)Total
Steven E. West(c)
$75,000 $90,621 $165,621 
Laurie H. Argo(c)
73,750 90,621 164,371 
Arturo Vivar(c)
73,750 90,621 164,371 
(a)This column reflects the value of a director’s annual retainer.
(b)The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.” Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.
(c)Each of Ms. Argo and Messrs. West and Vivar received a grant of 11,011 phantom units on July 10, 2020, which will vest and settle on July 10, 2021, pursuant to the LTIP, with each unit having a grant date fair value of $8.23. Each phantom unit is the economic equivalent of one of our common units.

Messrs. Stice and Van’t Hof are directors of our general partner, and are also executive officers of our general partner and employees of Diamondback E&P LLC. Messrs. Stice and Van’t Hof have received awards pursuant to the LTIP for their
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service as executive officers or employees, respectively, and unrelated to their service as directors of our general partner. These awards are reflected in the tables contained in Diamondback’s 2021 proxy statement under the heading “Compensation Discussion and Analysis.”
Compensation Committee Interlocks and Insider Participation

As previously noted, our general partner’s board of directors is not required to maintain, and does not maintain, a separate compensation committee. Messrs. Van’t Hof and Stice, each a director and executive officer of our general partner, are also directors and executive officers of Diamondback. However, all compensation decisions with respect to Messrs. Van’t Hof and Stice are made by Diamondback and Messrs. Van’t Hof and Stice do not receive any compensation directly from us or our general partner except for awards under our LTIP. As described in “– Compensation Discussion and Analysis,” decisions regarding the compensation of our general partner’s executive officers are made by Diamondback. See “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” and “Item 13. Certain Relationships and Related Transactions, and Director Independence” for more information about relationships among us, our general partner and Diamondback.

Compensation Policies and Practices as They Relate to Risk Management

We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Diamondback perform services on our behalf. See “–Compensation Discussion and Analysis” and “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” for more information about this arrangement. For an analysis of any risks arising from Diamondback’s compensation policies and practices, see Diamondback’s 2021 proxy statement. We have made awards of unit options subject to time-based vesting under our LTIP, which we believe drive a long-term perspective and which we believe make it less likely that our general partner’s executive officers will take unreasonable risks because the unit options retain value even in a depressed market.
 
ITEM 12.     SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Holdings of Officers and Directors

The following table presents information regarding the beneficial ownership of our common units as of January 31, 2021 by:

our general partner;
each of our general partner’s directors and executive officers; and
all of our general partner’s directors and executive officers as a group.
Name of Beneficial Owner
Common Units Beneficially Owned(1)
Percentage of Common Units Beneficially Owned
Rattler Midstream GP LLC
Travis D. Stice(2)
104,557*
Kaes Van’t Hof(3)
144,628*
Teresa L. Dick(4)
14,389*
Matt Zmigrosky(5)
5,795*
Laurie H. Argo(6)
6,214*
Arturo Vivar(6)
19,964*
Steven E. West(6)
34,264*
All directors and executive officers of our general partner as a group (7 persons)329,811*
*    Less than 1%
(1)Beneficial ownership is determined in accordance with SEC rules and generally includes voting or investment power with respect to securities. In computing percentage ownership of each person, (i) common units subject to options held by that person that are exercisable as of January 31, 2021 and (ii) common units subject to options or phantom units held by that person that are exercisable or vesting within 60 days of January 31, 2021 are all deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of
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each other person. The percentage of common units beneficially owned is based on 41,923,068 common units outstanding as of January 31, 2021. Unless otherwise indicated, all amounts exclude common units issuable upon the exercise of outstanding options and vesting of phantom units that are not exercisable and/or vested as of January 31, 2021 or within 60 days of January 31, 2021. Unless otherwise noted, the address for each beneficial owner listed below is 500 West Texas Avenue, Suite 1200, Midland, Texas 79701. Except as noted, each unitholder in the above table is believed to have sole voting and sole investment power with respect to the units beneficially held.
(2)All of these units are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Excludes 91,429 phantom units, that are scheduled to vest in four remaining equal installments beginning on May 28, 2021.
(3)Excludes 914,286 phantom units, that are scheduled to vest in four equal installments beginning on May 28, 2021.
(4)Excludes 45,714 phantom units, that are scheduled to vest in four equal installments beginning on May 28, 2021.
(5)Excludes 18,286 phantom units, that are scheduled to vest in four equal installments beginning on May 28, 2021.
(6)Excludes 11,011 phantom units, that are scheduled to vest on July 10, 2021.

 
The following table sets forth, as of January 31, 2021, the number of shares of common stock of Diamondback beneficially owned by each of the directors and executive officers of our general partner and all directors and executive officers of our general partner as a group.
 
Shares of Diamondback Common Stock Beneficially Owned(1)
Name of Beneficial OwnerAmount and Nature of
Beneficial Ownership
Percentage of
Class
Travis D. Stice(2)
462,480*
Kaes Van’t Hof(3)
38,222*
Teresa L. Dick(4)
50,603*
Matt Zmigrosky(5)
10,499*
Laurie H. Argo
Arturo Vivar
Steven E. West(6)
9,291*
All directors and executive officers as a group (7 persons)571,095*
*    Less than 1%.
(1)Beneficial ownership is determined in accordance with SEC rules. In computing percentage ownership of each person, (i) shares of common stock subject to options held by that person that are exercisable as of January 31, 2021 and (ii) shares of common stock subject to options or restricted stock units held by that person that are exercisable or vesting within 60 days of January 31, 2021, are all deemed to be beneficially owned. These shares, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of shares beneficially owned is based on 158,002,899 shares of common stock outstanding as of January 31, 2021. Unless otherwise indicated, all amounts exclude shares issuable upon the exercise of outstanding options and vesting of restricted stock units that are not exercisable and/or vested as of January 31, 2021 or within 60 days of January 31, 2021. Except as noted, each stockholder in the above table is believed to have sole voting and sole investment power with respect to the shares of common stock beneficially held.
(2)All of these shares are held by Stice Investments, Ltd., which is managed by Stice Management, LLC, its general partner. Mr. Stice and his spouse hold 100% of the membership interests in Stice Management, LLC, of which Mr. Stice is the manager. Includes 25,811 restricted stock units, that are scheduled to vest on March 1, 2021. Excludes 14,825 restricted stock units, that are scheduled to vest on March 1, 2022. Also excludes (i) 34,133 performance-based restricted stock units awarded on February 13, 2018, that vested effective December 31, 2020 (representing 112% vesting of the originally reported amount) based upon final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2020 by Diamondback’s compensation committee, (ii) 49,436 performance-based restricted stock units awarded to Mr. Stice on March 1, 2019, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021 and (iii) 66,714 performance-based restricted stock units awarded to Mr. Stice on March 1, 2020, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022.
(3)Includes 12,046 restricted stock units, that are scheduled to vest on March 1, 2021. Excludes (i) 6,918 restricted stock units, that are scheduled to vest on March 1, 2022, (ii) 8,790 restricted stock units, that are scheduled to vest in five equal
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annual installments beginning on March 1, 2025, (iii) 6,693 performance-based restricted stock units awarded on February 13, 2018, that vested effective December 31, 2020 (representing 112% vesting of the originally reported amount) based upon final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2020 by Diamondback’s compensation committee, (iv) 23,070 performance-based restricted stock units awarded on March 1, 2019, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021, (v) 13,183 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2019, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021 and are scheduled to vest in five equal annual installments beginning on March 1, 2025 and (vi) 31,133 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2020, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022.
(4)Includes 6,883 restricted stock units, that are scheduled to vest on March 1, 2021. Excludes 3,953 restricted stock units, that are scheduled to vest on March 1, 2022. Also excludes (i) 9,370 performance-based restricted stock units awarded to Ms. Dick on February 13, 2018, that vested effective December 31, 2020 (representing 112% vesting of the originally reported amount) based upon final determination upon certification of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2020 by Diamondback’s compensation committee, (ii) 13,183 performance-based restricted stock units awarded to Ms. Dick on March 1, 2019, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2021 and (iii) 17,790 performance-based restricted stock units awarded to Ms. Dick on March 1, 2020, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022.
(5)Includes 5,507 restricted stock units, that are scheduled to vest on March 1, 2021. Excludes 3,162 restricted stock units, that are scheduled to vest on March 1, 2022. Also excludes (i) 10,546 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2019, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021 and (ii) 14,232 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2020, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2022.
(6)Excludes 2,965 restricted stock units that are scheduled to vest on the earlier of the one-year anniversary of the date of grant and the date of the 2021 annual meeting of stockholders of Diamondback.


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Holdings of Major Unitholders

The following table sets forth certain information regarding the beneficial ownership of our common units and Class B units as of February 19, 2021 by each unitholder known by us to beneficially own 5% or more of our common units or Class B units.
Common UnitsClass B Units
Name and Address of Beneficial Owner
Amount and Nature of Beneficial Ownership(1)
Percentage of Class Beneficially Owned
Amount and Nature of Beneficial Ownership(1)
Percentage of Class Beneficially Owned
Diamondback Energy, Inc.(2)
      500 West Texas Avenue, Suite 1200
      Midland, Texas 79701
— — 107,815,152 100 %
ClearBridge Investments, LLC (3)
      620 8th Avenue
      New York, NY 10018
3,224,170 7.7 %— — 
Capital World Investors.(4)
      333 South Hope Street
      Los Angeles, CA 90071
2,859,750 6.8 %— — 
Zimmer Partners, LP (5)
      9 West 57th Street, 33rd Floor
      New York, NY 10019
2,336,799 5.6 %— — 
Kayne Anderson Capital Advisors, LP (6)
      1800 Avenue of the Stars, Third Floor
      Los Angeles, CA 90067
2,240,431 5.3 %— — 
(1)Beneficial ownership is determined in accordance with SEC rules. The percentage of common units beneficially owned is based on 41,923,068 common units outstanding as of January 31, 2021. Except as noted, each unitholder in the above table is believed to have sole voting and sole investment power with respect to the common units and Class B units beneficially held.
(2)Diamondback Energy, Inc. is a publicly traded company and holds no common units and no Class B units directly. Diamondback has the beneficial ownership of 107,815,152 Class B units, which are held by Energen Resources Corporation, its indirect wholly owned subsidiary (“Energen Resources”). The 107,815,152 Class B units, together with the same number of units of the Operating Company (each, an “OpCo unit”), held by Energen Resources, are exchangeable from time to time, at Diamondback’s discretion, for common units (that is, one OpCo unit and one Class B unit, together, are exchangeable for one common unit), and, as a result, Diamondback may be deemed to have the beneficial ownership of such common units. Diamondback also has shared voting and dispositive power of 107,815,152 Class B units held by Energen Resources, which represent 100% of the outstanding Class B units. The directors of Diamondback are Travis D. Stice, Steven E. West, Vincent K. Brooks, Michael P. Cross, David L. Houston, Stephanie K. Mains, Mark L. Plaumann and Melanie M. Trent. Travis D. Stice is the sole director of Energen Resources.
(3)Based solely on Schedule 13G/A filed with the SEC on February 11, 2021 by ClearBridge Investments, LLC (“ClearBridge”). The securities reported are beneficially owned by one or more open‑end investment companies or other managed accounts that are investment management clients of ClearBridge, an indirect wholly owned subsidiary of Franklin Resources, Inc. ClearBridge reported beneficial ownership of, as well as sole voting power and sole dispositive power over, 3,224,170 common units. No shared voting power and no shared dispositive power was reported by ClearBridge.
(4)Based solely on Schedule 13G filed with the SEC on February 16, 2021 by Capital World Investors (“Capital World”), a division of Capital Research and Management Company. Capital World reported beneficial ownership of, as well as sole voting power and sole dispositive power over, 2,859,750 common units. No shared voting power and no shared dispositive power was reported by Capital World.
(5)Based solely on Schedule 13G jointly filed with the SEC on January 11, 2021 by Zimmer Partners, LP, Sequentis Financial LLC, Zimmer Partners GP, LLC and Stuart J. Zimmer. Zimmer Partners, LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,336,799 common units. Sequentis Financial LLC reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,336,799 common units. Zimmer Partners GP, LLC reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,336,799 common units. Stuart J. Zimmer reported beneficial ownership of, as well as shared voting power
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and shared dispositive power over, 2,336,799 common units. No sole voting power and no sole dispositive power was reported by any filer.
(6)Based solely on Schedule 13G jointly filed with the SEC on January 29, 2021 by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne. Kayne Anderson Capital Advisors, L.P. reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,240,431 common units. Richard A. Kayne reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,240,431 common units. No sole voting power and no sole dispositive power was reported by any filer.

Securities Authorized For Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2020:
Plan CategoryNumber of securities to be issued upon exercise of outstanding options, warrants and rights (a)Weighted-average exercise price of outstanding options, warrants and rights (b)Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders— — — 
Equity compensation plans not approved by security holders(1)
2,089,668 — 12,755,210 
(1)This information relates to our LTIP, which our general partner adopted at the closing of the IPO in May 2019. For a description of the LTIP, see “Item 11. Executive Compensation– Long-Term Incentive Plan.”

Change in Control

Our general partner may transfer its general partner interest to a third party without the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the owner of our general partner to transfer its membership interests in our general partner to a third party. After any such transfer, the new member or members of our general partner would then be in a position to replace the board of directors and executive officers of our general partner with its own designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of control” without the vote or consent of the unitholders.

Treatment of Equity Awards Granted under the LTIP Upon Termination, Resignation and Death or Disability of Certain Executive Officers of our General Partner and Change of Control

The following sets forth information with respect to the treatment of the unvested equity awards, which were granted to the executive officers of our general partner and were outstanding as of December 31, 2020 under the LTIP, in connection with certain termination events, including a termination related to a change of control of Rattler or Diamondback.
Under the terms of Mr. Stice’s employment agreement with Diamondback and the terms of the phantom unit awards made to Mr. Stice under the LTIP, all unvested phantom unit awards granted to Mr. Stice will accelerate and immediately vest in the following circumstances: (i) upon the change of control of Rattler or Diamondback, provided that Diamondback is the sole general partner of Rattler, (ii) Mr. Stice’s termination without cause, (iii) Mr. Stice’s resignation for good reason, or (iv) Mr. Stice’s death or disability. As of December 31, 2020, Mr. Stice held 91,429 unvested phantom units granted under the LTIP, all which are scheduled to vest in four equal installments beginning on May 28, 2021, and had a value of $866,747 as of December 31, 2020.
Under the terms of Mr. Van’t Hof’s, Ms. Dick’s and Mr. Zmigrosky’s phantom unit awards made to these executive officers of our general partner under the LTIP, all of their unvested phantom unit awards will accelerate and immediately vest upon the change of control of Rattler or Diamondback, provided that Diamondback is the sole general partner of Rattler, or upon such executive officer’s death or disability. As of December 31, 2020, Mr. Van’t Hof held 914,286 unvested phantom units granted under the LTIP, all of which are scheduled to vest in four equal annual installments beginning on May 28, 2021, and had a value of $8,667,431 as of December 31, 2020; Ms. Dick held 45,714 unvested phantom units granted under the LTIP, all of which are scheduled to vest in four equal annual installments beginning on May 28, 2021, and had a value of $433,369 as of December 31, 2020; and Mr. Zmigrosky held 18,286 unvested phantom units granted under the LTIP, all of which are scheduled to vest in four equal annual installments beginning on May 28, 2021, and had an aggregate value of $173,351 as of December 31, 2020.
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No other executive officers of our general partner held equity awards under the LTIP as of December 31, 2020.
ITEM 13.     CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Agreements and Transactions with Affiliates

We have entered into certain agreements and transactions with Diamondback and its affiliates.

Commercial Agreements

The Partnership derives substantially all of its revenue from its commercial agreements with Diamondback for the provision of midstream services. Under the crude oil gathering agreement, we receive a volumetric fee per Bbl for gathering, transporting and delivering crude oil produced by Diamondback within the Dedicated Acreage. Under the natural gas gathering agreement, we receive a volumetric fee per MMBtu for gathering, compressing, transporting and delivering all natural gas produced by Diamondback within the Dedicated Acreage. Under the produced gathering and disposal agreement, we receive a volumetric fee per Bbl for gathering, transporting and disposing all produced water generated from operating crude oil and natural gas wells within the Dedicated Acreage. Under the sourced water gathering agreement, we receive a volumetric fee per Bbl for sourcing, transporting and delivering all raw sourced water and recycled sourced water required by Diamondback to carry out its oil and natural gas activities within the Dedicated Acreage. On May 5, 2020, the Partnership amended its commercial agreements to, among other things, in certain cases add new areas to the dedication and commitment of Diamondback and its affiliates and revise the threshold for permitting releases of dedications in connection with transfers or swaps by Diamondback or its affiliates.

Fasken Center Agreement

Under this agreement, Diamondback leases from us certain office space located within the Fasken Center in Midland, Texas.

Partnership Agreement

Under this agreement, the Partnership reimburses the General Partner for all direct and indirect expenses incurred or paid on the Partnership’s behalf and all other expenses allocable to the Partnership or otherwise incurred by the General Partner in connection with operating the Partnership’s business. The Partnership Agreement does not limit the amount of expenses for which its General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. See “Item 10—Directors, Executive Officers and Corporate Governance—Reimbursement of Expenses of our General Partner” for more details regarding the reimbursement provisions of our partnership agreement

Services and Secondment Agreement

Under this agreement, Diamondback seconds certain operational, construction, design and management employees and contractors of Diamondback to our general partner, us and our subsidiaries, or, collectively, the partnership parties, to provide management, maintenance and operational functions with respect to our assets. During their period of secondment, the seconded employees are under the direct management, supervision and control of Diamondback and its subsidiaries (other than the partnership parties) with respect to the provision of services to the partnership parties.

The partnership parties reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. If a seconded employee or contractor performs services for both Diamondback and its subsidiaries (other than the partnership parties) and the partnership parties, the partnership parties only reimburse Diamondback for a prorated portion of such employee’s overall wages and benefits or the costs associated with such contractor, in each case based on the percentage of the employee’s or contractor’s time spent working for the partnership parties, as determined in good faith by Diamondback and its subsidiaries (other than the partnership parties) and the partnership parties. The partnership parties will reimburse Diamondback on a monthly basis or at other intervals that Diamondback and the general partner may agree from time to time. The size of the reimbursement to Diamondback varies with the size and scale of our operations, among other factors.

The services and secondment agreement has an initial term of 15 years and automatically extends for successive extension terms of one year each, unless terminated by either party upon at least 30 days’ prior written notice before the end of the initial term or any extension term. In addition, the partnership parties may terminate the agreement in whole at any time
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upon written notice stating the date of termination or terminate any particular service provided to the partnership parties by a seconded employee or contractor under the agreement at any time upon 30 days’ prior written notice.

Distributions paid to Diamondback

Diamondback is entitled to receive its pro rata portion of the distributions the Operating Company makes in respect of the OpCo units. However, Diamondback is not entitled to receive cash distributions on our Class B units that it beneficially owns, except to the extent of the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution it made to us. During the year ended December 31, 2020, Diamondback received distributions from the Operating Company in the aggregate amount of $115.4 million.

Tax Sharing Agreement
Under this agreement, the Operating Company reimburses Diamondback for our share of state and local income and other taxes for which the Operating Company’s results are included in a combined or consolidated tax return filed by Diamondback. The amount of any such reimbursement is limited to the tax that the Operating Company would have paid had it not been included in a combined group with Diamondback. Diamondback may use its tax attributes to cause its combined or consolidated group, of which OpCo may be a member for this purpose, to owe less or no tax. In such a situation, the Operating Company agreed to nevertheless reimburse Diamondback for the tax the Operating Company would have owed had the attributes not been available or used for its benefit, even though Diamondback had no cash tax expense for that period.

The following table presents the Partnership’s revenues generated or expenses incurred under these agreements or through transactions with Diamondback during the year ended December 31, 2020.

Year Ended December 31, 2020
(In thousands)
Revenues Generated under Agreements and Transactions with Affiliates
Produced water gathering and disposal commercial agreement$281,106 
Sourced water gathering commercial agreement$67,336 
Natural gas gathering commercial agreement$20,479 
Crude oil gathering commercial agreement$10,006 
Surface revenue transactions$162 
Fasken Center agreement$7,801 
Expenses Incurred under Agreements with Affiliates
Services and Secondment agreement$5,906 
Partnership agreement$742 
Tax Sharing agreement$206 

Procedures for Review, Approval and Ratification of Related Person Transactions

The board of directors of our general partner adopted policies for the review, approval and ratification of transactions with related persons. Under our Code of Ethics, a director is expected to bring to the attention of the chief executive officer or the board of directors of our general partner any conflict or potential conflict of interest that may arise between the director or any affiliate of the director, on the one hand, and us or our general partner on the other. The resolution of any such conflict or potential conflict should, at the discretion of the board of directors of our general partner in light of the circumstances, be determined by a majority of the disinterested directors.

If a conflict or potential conflict of interest arises between our general partner or its affiliates, on the one hand, and us or our common unitholders, on the other hand, the resolution of any such conflict or potential conflict should be addressed by the board of directors of our general partner in accordance with the provisions of our partnership agreement. At the discretion of the board of directors of our general partner in light of the circumstances, the resolution may be determined by the board of directors of our general partner in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

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Pursuant to our Code of Ethics, any executive officer is required to avoid conflicts of interest unless approved by the board of directors of our general partner.

Our Code of Ethics described above was adopted at the closing of our IPO, and as a result, the transactions described above were not reviewed according to such procedures.

Director Independence

The information required by Item 407(a) of Regulation S-K is included in “Item 10. Directors, Executive Officers and Corporate Governance” above.

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

The audit committee of the board of directors of our general partner selected Grant Thornton LLP, an independent registered public accounting firm, to audit our consolidated financial statements for the years ended December 31, 2020 and 2019. The audit committee’s charter requires the audit committee to approve in advance all audit and non-audit services to be provided by our independent registered public accounting firm. All services reported in the audit, audit-related, tax and all other fees categories below with respect to our annual reports for the years ended December 31, 2020 and 2019 were approved by the audit committee.

The following table summarizes the aggregate Grant Thornton LLP fees that were allocated to us for independent auditing, tax and related services:
Year Ended December 31,
20202019
(In thousands)
Audit fees(1)
$365 $442 
Audit-related fees(2)
66 — 
Tax fees(3)
— — 
All other fees(4)
— — 
Total$431 $442 
(1)Audit fees represent amounts billed in each of the years presented for assurance and related services that are reasonably related to the performance of the annual audit or quarterly reviews.
(2)Audit-related fees represent amounts billed for each of the periods presented for professional services rendered in connection with those services normally provided in connection with statutory and regulatory filings or engagements including comfort letters, consents and other services related to SEC matters.
(3)Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.
(4)All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above.

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PART IV
ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES