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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, 2021

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 class Trading Symbol(s) Name of each exchange on which registered
Common Units RTLR The 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 Filer Accelerated Filer
Non-Accelerated Filer Smaller Reporting Company
Emerging Growth Company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.     
Indicate by check mark whether the registrant 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 $443.2 million on June 30, 2021, 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 18, 2022, 38,139,805 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, 2021
TABLE OF CONTENTS
Page
1
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.
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.
MMcf One million cubic feet of natural gas.
MMcf/d One million 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.
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.
ii

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.

GLOSSARY OF CERTAIN OTHER TERMS
The following is a glossary of certain other terms used in this report:
ASU Accounting Standards Update.
ASC Accounting Standards Codification.
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.
FASB Financial Accounting Standards Board.
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.
Holding Company Rattler Holdings LLC, a wholly owned subsidiary of Rattler.
IPO
The Partnership’s initial public offering.
LIBOR The London interbank offered rate.
LTIP Rattler Midstream LP Long Term Incentive Plan.
Nasdaq
The Nasdaq Global Select Market.
Notes The $500.0 million in aggregate principal amount of 5.625% Senior Notes due 2025 issued on July 14, 2020.
Operating Company
Rattler Midstream Operating LLC, a Delaware limited liability company and a consolidated subsidiary of the Partnership.
OPEC The Organization of the Petroleum Exporting Countries.
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.
RRC The Railroad Commission of Texas.
SEC
Securities and Exchange Commission.
Securities Act
The Securities Act of 1933, as amended.

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report contains “forward-looking statements” within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding our: future performance; business strategy; future operations; estimates and projections of revenues, losses, costs, expenses, returns, cash flow, and financial position; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including plans for future cash flow from operations) are forward-looking statements. When used in this document, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to the Partnership are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although we believe that the expectations and assumptions reflected in our forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond our control. Accordingly, forward-looking statements are not guarantees of future performance and our actual outcomes could differ materially from what we have expressed in our forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of the Partnership and its consolidated subsidiaries.

Factors that could cause our outcomes to differ materially include (but are not limited to) the following:

Diamondback’s ability to meet its drilling and development plans on a timely basis or at all;
changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities;
the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions;
actions taken by the members of OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;
changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, and inflation rates;
regional supply and demand factors, including delays, curtailment delays or interruptions of production, or governmental orders, rules or regulations that impose production limits;
federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
restrictions on the use of water, including limits on the use of produced water and a moratorium on new produced water well permits recently imposed by the RRC in an effort to control induced seismicity in the Permian Basin;
significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;
changes in U.S. energy, environmental, monetary and trade policies;
conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development operations and our environmental and social responsibility projects;
challenges with employee retention and an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic;
changes in the demand for and costs of conducting midstream infrastructure services;
changes in safety, health, environmental, tax, and other regulations or requirements (including those addressing air emissions, water management, or the impact of global climate change);
security threats, including cybersecurity threats and disruptions to our business and operations from breaches of our information technology systems, or from breaches of information technology systems of third parties with whom we transact business;
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 results of our investments in joint ventures;
the conditions impacting the timing and amount of common units repurchased under our common unit repurchase program;
severe weather conditions;
acts of war or terrorist acts and the governmental or military response thereto;
iv

defaults by Diamondback under our commercial agreements;
changes in the financial strength of counterparties to our credit agreement;
changes in our credit rating; and
the risk factors discussed in Item 1A of Part I of this Annual Report on Form 10-K.

In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, we operate in a very competitive and rapidly changing environment and new risks emerge from time to time. We cannot 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 anticipated by any forward-looking statements we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this document. All forward-looking statements speak only as of the date of this document 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 applicable law.

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PART I
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 “Holding Company” or “HoldCo” refer to Rattler Holdings LLC, (iv) the “Operating Company” refer to Rattler Midstream Operating LLC, and (v) “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 publicly traded 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.

On December 22, 2021, we completed an internal reorganization, which we refer to as the Reorganization, including the contribution, which we refer to as the Contribution, of 100% of the limited liability company interests we held in the Operating Company to the Holding Company, our newly-formed, wholly-owned subsidiary. As a result of the Contribution, the Holding Company was admitted as a member of the Operating Company, and replaced us as the managing member of the Operating Company.

Our operations are conducted through, and our operating assets are owned by, the Operating Company. As of December 31, 2021, the Holding Company directly owned a 26% membership interest and 100% of the sole managing membership interest in the Operating Company, while Diamondback owned a 74% economic, non-voting interest in the Operating Company. Our assets and operations are reported in one business segment. Effective in the first quarter of fiscal 2021, the Partnership determined the former real estate operations segment no longer met the criteria to be an operating segment due to a change in focus and the relative immateriality of the activity.

We are Diamondback’s primary provider of water-related midstream services (including water sourcing and transportation and produced water gathering and disposal) and a significant provider of long-term crude oil gathering and, as such, are critical to its development plans. We have long-term acreage dedications, which we refer to as the Acreage Dedications, from Diamondback spanning approximately 450,000 gross acres on Diamondback’s core leasehold in the Permian (approximately 265,000 gross acres in the Midland Basin and approximately 185,000 gross acres in the Delaware Basin). We entered into commercial agreements with Diamondback in June 2018, effective as of January 1, 2018, that have initial terms ending in 2034.

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.

Significant 2021 and 2022 Acquisitions and Divestitures

Acquisitions

WTG Joint Venture Acquisition

On October 5, 2021, we and a private affiliate of an investment fund formed Remuda Midstream Holdings LLC, which we refer to as the WTG joint venture. The Operating Company invested approximately $104.0 million in cash to acquire a 25% interest in the WTG joint venture, which then completed an acquisition of a majority interest in WTG Midstream LLC, or WTG Midstream, from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.

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Drop Down Transaction

On December 1, 2021, we acquired certain water midstream assets from Diamondback and certain of its subsidiaries for $160.0 million, including closing adjustments, in cash in a drop down transaction that we refer to as the Drop Down. We funded the transaction with borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control, with assets recognized at Diamondback’s historical carrying value.

The Drop Down assets include nine active saltwater disposal injection wells with 330 MBbl/d of capacity, seven produced water recycling and storage facilities, 20 fresh water pits and approximately 4,000 acres of fee surface. Also included are 55 miles of produced water gathering pipeline and 18 miles of sourced water gathering pipeline.

BANGL Joint Venture Acquisition

On January 19, 2022, we invested approximately $22.2 million in cash to acquire a 10% interest in BANGL, LLC, which we refer to as the BANGL joint venture. The BANGL pipeline, which began full commercial service in the fourth quarter of 2021, provides NGL takeaway capacity from MPLX and WTG gas processing plants in the Permian Basin to the NGL fractionation hub in Sweeny, Texas and has expansion capacity of up to 300,000 Bbl/d.

Divestitures

Amarillo Rattler Divestiture

On April 30, 2021, we and our joint venture partner, Amarillo Midstream, LLC, each sold our respective 50% interests in Amarillo Rattler, LLC, which we refer to as Amarillo Rattler, to EnLink Midstream Operating, LP. Net of transaction expenses and working capital adjustments, we received $23.5 million at closing. An incremental $5.0 million is payable to us in April 2022, and we could receive up to $7.5 million in total contingent earn-out payments from 2023 to 2025.

Real Estate Divestiture

On June 28, 2021, we closed on the sale of one of our real estate properties located in Midland, Texas for proceeds of $9.1 million, including closing adjustments, which resulted in a loss on disposal of $0.4 million.

Pecos County Gas Gathering Divestiture

On November 1, 2021, we completed the sale of substantially all of our natural gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream, for aggregate total gross potential consideration of $93.0 million, consisting of (i) $83.0 million paid at closing, after customary closing adjustments, (ii) a $5.0 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of Diamondback and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5.0 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of Diamondback and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable.

See Note 4—Acquisitions and Divestitures and Note 16—Subsequent Events included in the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of these transactions.

Our Assets

As of December 31, 2021, we own and operate 866 miles of crude oil, sourced water and produced water gathering pipelines on acreage that overlays Diamondback’s core Midland and Delaware Basin development areas. Our water system obtains, stores 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 gathering systems transport oil from the infield production batteries to intermediary pipelines. Additionally, we own equity interests in three long-haul crude oil pipelines and one NGL pipeline 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.

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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 includes a network of gathering pipelines that collect and transport crude oil, 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.

The following table provides information regarding our gathering, compression and transportation system as of December 31, 2021:
Pipeline Infrastructure Assets
(miles)(1)
Delaware Basin Midland Basin Permian Total
Crude oil 113  46  159 
Produced water 273  310  583 
Sourced water 27  97  124 
Total 413  453  866 

(capacity/capability)(1)
Delaware Basin Midland Basin Permian Total Utilization
Crude oil gathering (Bbl/d) 240,000  65,000  305,000  27  %
Produced water gathering and disposal (Bbl/d) 1,330,000  2,134,000  3,464,000  24  %
Sourced water gathering (Bbl/d) 120,000  544,000  664,000  43  %
(1)Does not include any assets of our equity method investment joint ventures.

The following table provides information regarding our throughput volumes for each of the periods indicated:
Year Ended December 31,
(throughput)(1)
2021 2020 2019
Crude oil gathering (Bbl/d) 79,071  92,056  85,164 
Natural gas gathering (MMBtu/d) 112,130  121,637  85,283 
Produced water gathering and disposal (Bbl/d) 783,259  821,543  806,078 
Sourced water gathering (Bbl/d) 268,259  253,907  415,939 
(1)Does not include any volumes from our equity method investment joint ventures.

Crude oil gathering and transportation assets

As of December 31, 2021, excluding the assets of our joint ventures discussed below, our crude oil gathering system consists of (i) 159 miles of crude oil pipelines, which have 305,000 Bbl/d of crude oil throughput capacity and 118,000 Bbl of crude oil storage. Our crude oil 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 gathered volumes, excluding volumes gathered by our joint ventures, averaged 79 MBbl/d for the year ended December 31, 2021.

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 that accompany 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, treatment and recycling. We own strategically located produced water gathering pipeline systems spanning a total of 583 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, 2021, we have a total of 141 produced water disposal wells with an aggregate capacity of 3.5 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 23% of the sourced water volumes sold by Rattler were recycled produced water during the year ended December 31, 2021. We have and expect to continue to realize increased margins for produced water disposal as a result of this recycling program.

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Water sourcing and distribution assets

Our water sourcing and distribution system, with storage capacity of 75 MMBbl/d, is critical to Diamondback’s completion operations, and obtains, stores 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, produced water treatment facilities 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.

Investment in long-haul crude oil and NGL pipelines

We own a 10% equity interest in each of EPIC Crude Holdings LP, Gray Oak Pipeline, LLC, and BANGL, LLC, and a 4% equity interest in Wink to Webster Pipeline LLC. We refer to these joint ventures as the EPIC, Gray Oak, BANGL 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 long-haul crude oil and NGL 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, which we refer to as the Gray Oak Pipeline, is capable of transporting approximately 900,000 Bbl/d.

BANGL, which began full commercial service in the fourth quarter of 2021, provides NGL takeaway capacity from the MPLX and WTG gas processing plants in the Permian Basin to the NGL fractionation hub in Sweeny, Texas and has expansion capacity of up to 300,000 Bbl/d.

Wink to Webster owns and operates 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 first quarter of 2022. 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 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 245 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 own a 25% equity interest in the WTG joint venture, which owns a majority interest in WTG Midstream. WTG Midstream has assets primarily consisting of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.

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Our Relationship with Diamondback

    As of December 31, 2021, 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 74% of our total units outstanding. Diamondback also owns and controls our General Partner.

We believe Diamondback views our assets 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 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 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 consistent requirements for our midstream services, 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 method joint ventures, which are expected to be minimal going forward as the majority of 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. Pursuant to the Acreage Dedications, we will continue to provide sourced water handling and gathering, produced water handling and disposal and crude oil transportation and gathering 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 Acreage Dedications and we intend to utilize this relationship with Diamondback to drive free cash flow. Significant past investment in building or acquiring our midstream assets will allow us to support Diamondback’s expected production volumes, even as our expected operating capital expenditures decline.

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, all of which are at or near their full length and capacity and should have minimal capital contributions going forward, 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 our assets 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 execute on its development plan. 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.
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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 and 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. The close proximity of our assets 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 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 the preceding 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 fee-based commercial agreements with Diamondback, which are based upon the prevailing market rates at the time of execution with annual escalators (subject to potential adjustment by regulators). We believe such agreements 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 should result in minimal incremental operating capital expenditures to meet Diamondback’s anticipated production 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, 2021, we had $425 million of liquidity, including $405 million of available borrowings under our credit agreement, and a debt to equity ratio of approximately 0.7 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 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 and interstate and intrastate pipelines. 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.

Within the Acreage Dedications, we do not compete with other midstream companies to provide Diamondback with midstream services. However, for certain midstream services within the Acreage Dedications, Diamondback may continue to use third party service providers until the expiration or termination of certain pre-existing dedications.

Seasonal Nature of Business

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.

Regulation

The midstream services we provide are subject to regulations that may affect certain aspects of our business and the market for our services.
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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, seismically sensitive areas, 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. 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” below. 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
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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, on August 13, 2020, in response to an executive order by former President Trump to review and revise unduly burdensome regulations, the EPA amended the New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some technical changes) thereby reinstating the 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on November 15, 2021, the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. These new 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. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce GHG emissions, including reducing global methane emissions by at least 30% by 2030. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international climate commitments.

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
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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, the severe winter storms in the Permian Basin in February 2021, 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 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.

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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, as amended, 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.

The scope of waters regulated under the CWA has fluctuated in recent years. 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 CWA. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules, and then on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, which significantly reduced the waters subject to federal regulation under the CWA. On August 30, 2021, a federal court struck down the replacement rule and, on December 7, 2021, the EPA and the Corps published a proposed rule that would put back into place the pre-2015 definition of “waters of the United States,” updated to reflect Supreme Court decisions, while the agencies continue to consult with stakeholders on future regulatory actions. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the CWA. To the extent the rules expand the range of properties subject to the CWA’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas

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 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.
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Hydraulic Fracturing

We do not conduct hydraulic fracturing operations, but substantially all of Diamondback’s crude oil and natural gas production on the Acreage Dedications are 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.

We dispose of large volumes of produced water, gathered from Diamondback and other customers in connection with their respective drilling and producing operations, and inject it into wells pursuant to permits issued to us by governmental authorities overseeing such activities. While these permits are issued pursuant to the Safe Drinking Water Act and other implementing laws and regulations, the legal requirements are subject to change, which could result in imposition of more stringent operating constraints or new monitoring and reporting requirements. Regulators in some states have sought additional requirements to assess the relationship between seismicity and the use of disposal wells. For example, the RRC has recently imposed standards for operators of disposal wells to assess risk in seismically active areas. Additionally, the RRC can impose increased frequency of injection data to the state, inclusive of daily rate and pressure. Utilizing the permit required for risk assessment and increased data density, if the applicant of a disposal well cannot demonstrate that the produced water or other fluids are confined to the disposal zone or are likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing permit for such well. The RRC has used this authority to deny permits and temporarily suspend operations for disposal wells, and in September 2021, the RRC curtailed the amount of water companies are permitted to inject into some wells near Midland and Odessa in the Permian Basin. Since this action, the RRC has indefinitely suspended some permits and identified other areas of increased seismic risk with associated imposition of permit modification. These restrictions on disposal of produced water could result in increased operating costs through alternative water handling strategies, not limited to, trucking water to low risk areas, recycling of produced water, or pumping it through a pipeline network to low risk areas.

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. However, 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
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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.

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 $225,134 and $2,251,334, 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. Also, on November 15, 2021, PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures. 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 strengthen integrity management assessment requirements. Also, on June 7, 2021, PHMSA issued an advisory bulletin reminding pipeline owners and operators that, pursuant to legislation signed into law in December 2020, they must take several steps to eliminate hazardous leaks and minimize releases of natural gas by December 27, 2021. These requirements 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 RRC 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
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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.

 
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 $1.3 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 RRC. 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 RRC’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 RRC retains authority to regulate the installation, reclamation, operations, maintenance, and repair of gathering systems should the RRC choose to do so. Should the RRC 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 RRC. However, the RRC 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.

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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 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 0.78 percent, which is in effect until June 30, 2026. 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 RRC 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 Holding Company, 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.

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 could continue to be adversely affected by the ongoing COVID-19 pandemic and volatility in the oil and natural gas markets.

After briefly reaching negative levels in April 2020, oil prices recovered during 2021, closing at $85.43 per bbl WTI as of January 18, 2022, spurred by the global economic recovery from the COVID-19 pandemic and producer restraint. Demand for oil and natural gas increased during 2021, as many restrictions on conducting business implemented in response to the COVID-19 pandemic were lifted due to improved treatments and availability of vaccinations in the U.S. and globally. The emergence of the Delta COVID-19 variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant, however, continue to contribute to economic and pricing volatility and a cautious production outlook for 2022, as industry and market participants evaluate the potential impact of Omicron COVID-19 cases. Further, on January 4, 2022, OPEC and its non-OPEC allies, known collectively as OPEC+, agreed to continue their program (commenced in August 2021) of gradual monthly output increases in February 2022, raising its output target by 400,000 Bbl per day, which move is expected to boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 MBbl per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in commodity prices or demand for crude oil.

Notwithstanding the return of crude oil demand, Diamondback has announced capital plans to maintain its fourth quarter 2021 production volumes for 2022. Because we derive substantially all of our revenue from our commercial agreements with Diamondback, which do not contain minimum volume commitments, any reductions of Diamondback’s drilling and development plan on our Acreage Dedications could have a direct and adverse impact on Diamondback’s demand for our midstream services and, consequently, our results of operations.

Besides the impact of the ongoing COVID-19 pandemic and actions by OPEC+, other significant factors that are likely to continue to affect commodity prices in future periods include, but are not limited to, the effect of U.S. energy, monetary and trade policies, U.S. and global economic conditions, U.S. and global political and economic developments, including the Biden Administration’s energy and environmental policies and the potential impact of any Russian-Ukrainian conflict on the global energy markets, all of which are beyond our control.

The ongoing COVID-19 pandemic continues to present operational, health, labor, logistics and other challenges, and it is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and cash flows.

There are many variables and uncertainties regarding the COVID-19 pandemic, including the emergence, contagiousness and threat of new and different strains of the virus and their severity; the effectiveness of treatments or vaccines against the virus or its new strains; the extent of travel restrictions, business closures and other measures that are or may be imposed in affected areas or countries by governmental authorities; disruptions in the supply chain; an increasingly competitive labor market due to a sustained labor shortage or increased turnover caused by the COVID-19 pandemic; increased logistics costs; additional costs due to remote working arrangements, adherence to social distancing guidelines and other COVID-19-related challenges. Further, there remain increased risks of cyberattacks on information technology systems used in remote working environment; increased privacy-related risks due to processing health-related personal information; absence of workforce due to illness; the impact of the pandemic on any of our contractual counterparties; and other factors that are currently unknown or considered immaterial. It is difficult to assess the ultimate impact of the COVID-19 pandemic on our business, financial condition and cash flows.

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We derive substantially all of our revenue from Diamondback. If Diamondback changes its business strategy, alters its current drilling and development plan on the Acreage Dedications, or otherwise significantly reduces the volumes of crude oil, 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 Acreage Dedications; 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 Acreage Dedications; 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 Acreage Dedications, prioritize planned development on acreage outside of the Acreage Dedications, sell any of the Acreage Dedications to a third party whose financial 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, 2021, 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.

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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 Acreage Dedications and the volumes of hydrocarbons and water that are produced on the Acreage Dedications and for which we provide midstream services; Diamondback’s and our other customers’ ability to fund their drilling and development plan on the Acreage Dedications; 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, BANGL, WTG Midstream 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.

The board of directors of our General Partner 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” included elsewhere in this Annual Report.

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, BANGL, WTG 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.

Certain of these joint ventures have incurred substantial debt and servicing such debt or complying with debt covenants may limit the ability of the joint ventures to make distributions to us and the other joint venture partners. 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.
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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.


Any impairment of our long -lived assets or equity method investments will reduce our earnings and could negatively impact the value of our common units.

Consistent with GAAP, we evaluate our long-lived assets and equity method investments whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. For our equity method investments, the impairment test requires us to consider whether the fair value of the investment, not just that of the underlying net assets, has declined and whether that decline is other than temporary. If we determine that an other than temporary impairment is indicated, we are required to record a non-cash charge to earnings with a corresponding reduction in the carrying value of the investment.

The risk of future impairments related to our long-lived assets or equity method investments will continue to exist. If underlying business assumptions change, there can be no assurance that a future impairment charge will not be made with respect to our remaining balances of our equity method investments and long-lived assets. This could have a negative impact on our common unit price. For further discussion of the impairment of long-lived assets and equity method investments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates—Equity Method Investments” and “Note 6—Property, Plant and Equipment” in the notes to the consolidated financial statements included elsewhere in this Annual Report.

Acreage Dedications 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.
The majority of the land on which our midstream systems have been constructed is owned by third parties or 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 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 the severe winter storms in the Permian Basin in February 2021, or interruption of the processing or transportation of crude oil 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.

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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.

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 and water sources to our existing infrastructure, obtain them in a cost-efficient manner or capitalize on other attractive expansion opportunities.

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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 RRC, 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 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
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” included elsewhere in this Annual Report for a description of certain laws and regulations that affect or could affect our operations.

Changes in environmental laws could increase our or our operators’ costs and adversely impact our business, financial condition and cash flows.

President Biden has indicated that he is supportive of, and has issued 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 decarbonize electric generation and the transportation sector. 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
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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 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 or NGLs or losses of crude oil 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 could increase and 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 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 Holding Company, 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. 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 it would otherwise provide to us if it were solely focused on our business and operations. 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.

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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 $17.0 million on our balance sheet related to our future closure obligations of our produced water facilities and oil gathering systems as of December 31, 2021. 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 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 or armed conflict could harm our business.

Terrorist activities, anti-terrorist efforts and other armed conflicts involving the United States or other countries 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 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 the employees of Diamondback and our 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.

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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.

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 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
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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, which has indicated plans for multiple rate increases in 2022, 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), which we refer to as the FCA, announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. On March 5, 2021, the ICE Benchmark Administration, which administers LIBOR, and the FCA announced that all LIBOR settings will either cease to be provided by any administrator, or no longer be representative immediately after 2021, for all non-U.S. dollar LIBOR settings and one-week and two-month U.S. dollar LIBOR settings, and immediately after June 30, 2023 for the remaining U.S. dollar LIBOR settings. In light of these announcements, the future of LIBOR at this time is uncertain and any changes in the methods by which LIBOR is determined or regulatory activity related to LIBOR’s phase-out could cause LIBOR to perform differently than in the past or cease to exist. Our current credit agreement provides for any changes away from LIBOR to a successor rate to be based on prevailing or equivalent standards, however, changes in the method of calculating LIBOR, or the discontinuation, reform, or replacement of LIBOR or any other benchmark rates may adversely affect interest rates and result in higher borrowing costs. This could materially and adversely affect our results of operations, cash flow and liquidity.


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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;
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.

Our General Partner may exercise its right to call and purchase common units if it and its affiliates own more than 80% of the common units and Class B units, taken together and such right may be exercised at an undesirable time or price.

If at any time our General Partner and its affiliates own more than 80% of our common units, our General Partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing price of our common units over the 20 consecutive trading days preceding the date three days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our General Partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their units. Our General Partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our General Partner from causing us to issue additional common units and then exercising
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its call right. If our General Partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act and our common units will no longer be listed or traded on the Nasdaq Global Select Market. As of February 18, 2022, Diamondback owned all of our 107,815,152 outstanding Class B units, together with the same number of Operating Company units, which are exchangeable from time to time, at Diamondback’s discretion, for common units. Such units represent approximately 74% of our total units outstanding.

Holders of our common units have limited voting rights and are not entitled to elect our General Partner or its directors, or 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 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, 2021, Diamondback owned all of our 107,815,152 outstanding Class B units representing 74% of our total units outstanding. 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.

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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 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.
    
Our partnership agreement does not limit 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.

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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 Operating Company 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 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.

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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 have 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 or utilize net operating losses to offset a portion of our taxable income over the next several years, 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.

Future U.S. tax legislation 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 “Note 15—Commitments and Contingencies” included in the notes to the consolidated financial statements included elsewhere in this Annual Report.

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 were two holders of record of our common units on February 18, 2022.

Cash Distribution Policy

The board of directors of our General Partner sets and administers the cash distribution policies for the Partnership and the Operating Company. Cash distributions paid by the Operating Company to Diamondback and the Partnership as the beneficial owners of the Operating Company’s common units are determined by the board of directors of our General Partner on a quarterly basis. 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, 2021 was as follows:
Period Total Number of Units Purchased
Average Price Paid Per Unit (1)
Total Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan (2)
($ in thousands, except per unit amounts)
October 1, 2021 - October 31, 2021 156,480 $ 11.92  156,480 $ 104,768 
November 1, 2021 - November 30, 2021 676,797 $ 11.14  676,797 $ 97,229 
December 1, 2021 - December 31, 2021 872,200 $ 10.96  872,200 $ 87,668 
Total 1,705,477 $ 11.12  1,705,477
(1)The average price paid per common unit includes commissions paid to repurchase common units.
(2)In October 2020, the board of directors of our General Partner approved an initial common unit repurchase program to acquire up to $100.0 million of our outstanding common units through December 31, 2021. In October 2021, the repurchase program authorization was increased to $150.0 million and the program was extended indefinitely. 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.

Recent Sales of Unregistered Securities
None.

ITEM 6.    [RESERVED]

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” included elsewhere in this Annual Report.

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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 one operating business segment. We have elected to be treated as a corporation for U.S. federal income tax purposes.

We provide crude oil 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, 2021, our midstream infrastructure assets include 866 miles of pipeline across the Midland and Delaware Basins with approximately 305,000 Bbl/d of crude oil gathering capacity, 3.5 MMBbl/d of produced water disposal capacity and 664,000 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 and one NGL pipeline 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 and water-related services needs through our robust infield gathering systems and produced water disposal capabilities.

As of December 31, 2021, our General Partner held 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 74% of our total units outstanding. Diamondback also owns and controls our General Partner.

On December 22, 2021, we completed the Reorganization, which included the Contribution of 100% of the limited liability company interests we held in the Operating Company to the Holding Company. As a result of the Contribution, the Holding Company was admitted as a member of the Operating Company, and replaced the Partnership as the managing member of the Operating Company.

As of December 31, 2021, the Holding Company owned a 26% membership interest and 100% of the sole managing membership interest in the Operating Company, and Diamondback owned, through its ownership of the Operating Company units, a 74% economic, non-voting interest in the Operating Company. As required by GAAP, we consolidate 100% of the assets and operations of the Holding Company and 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 2021 and 2020. A discussion of changes in our results of operations from fiscal year 2019 to fiscal year 2020 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, 2020, filed with the SEC on February 25, 2021 and incorporated by reference into this Annual Report.

2021 Transactions and Recent Developments

COVID-19 and Effects on Commodity Prices

After briefly reaching negative levels in April 2020, oil prices recovered during 2021, spurred by the global economic recovery from the COVID-19 pandemic and producer restraint. Demand for oil and natural gas increased during 2021, as many restrictions on conducting business, implemented in response to the COVID-19 pandemic, have been lifted due to improved treatments and availability of vaccinations in the U.S. and globally. However, the emergence of the COVID-19 Delta variant in the latter part of 2021 and the subsequent surge of the highly transmissible Omicron variant continued to contribute to the economic and pricing volatility and cautious oil and natural gas production outlook for 2022, as industry and market participants evaluate the potential impact of Omicron variant cases. Further, on January 4, 2022, OPEC+ agreed to continue their program (commenced in August 2021) of gradual monthly output increases in February 2022, raising its output target by 400,000 Bbl per day, which move is expected to further boost oil supply in response to rising demand. In its report issued on February 10, 2022, OPEC noted its expectation that world oil demand will rise by 4.15 MBbl per day in 2022, as the global economy continues to post a strong recovery from the COVID-19 pandemic. Although this demand outlook is expected to underpin oil prices, already seen at a seven-year high in February 2022, we cannot predict any future volatility in commodity prices or demand for crude oil.

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Despite the recovery in commodity prices and rising demand, Diamondback kept its production relatively flat during 2021, using excess cash flow for debt repayment and/or return to its stockholders rather than expanding its drilling program.

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. Reduced demand stemming from the price volatility discussed above has had and may continue to have a detrimental effect on our sourced water business line and our overall operations. Diamondback recently announced its 2022 production target of between 218,000 and 222,000 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 Acreage Dedications or to perform under our commercial agreements.

During 2021, we reduced operated capital expenditures to less than 25% of 2020 levels and less than 15% of 2019 levels. Combined with the fact that our equity method joint venture build cycle is nearing its end, and changing from a net outflow of capital contributions to a net inflow of cash distributions, we believe that this stabilized volume outlook will present meaningful free cash flow generation in the current commodity price environment.

Acquisitions

WTG Joint Venture Acquisition

On October 5, 2021, we and a private affiliate of an investment fund formed the WTG joint venture. The Operating Company invested approximately $104.0 million in cash to acquire a 25% interest in the WTG joint venture, which then completed an acquisition of a majority interest in WTG Midstream from West Texas Gas, Inc. and its affiliates. WTG Midstream’s assets primarily consist of an interconnected gas gathering system and six major gas processing plants servicing the Midland Basin with 925 MMcf/d of total processing capacity with additional gas gathering and processing expansions planned.

Drop Down Transaction

On December 1, 2021, we acquired certain water midstream assets from Diamondback and certain of its subsidiaries for $160.0 million, including closing adjustments, in cash in a drop down transaction. We funded the transaction with borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control, with assets recognized at Diamondback’s historical carrying value in the consolidated balance sheet.

The Drop Down assets include nine active saltwater disposal injection wells with 330 MBbl/d of capacity, seven produced water recycling and storage facilities, 20 fresh water pits and approximately 4,000 acres of fee surface. Also included are 55 miles of produced water gathering pipeline and 18 miles of sourced water gathering pipeline.

BANGL Joint Venture Acquisition

On January 19, 2022, we invested approximately $22.2 million in cash to acquire a 10% interest in the BANGL joint venture. The BANGL pipeline, which began full commercial service in the fourth quarter of 2021, provides NGL takeaway capacity from MPLX and WTG gas processing plants in the Permian Basin to the NGL fractionation hub in Sweeny, Texas and has expansion capacity of up to 300,000 Bbl/d.

Divestitures

Amarillo Rattler Divestiture

On April 30, 2021, we and our joint venture partner, Amarillo Midstream, LLC, each sold our respective 50% interests in Amarillo Rattler to EnLink Midstream Operating, LP. Net of transaction expenses and working capital adjustments, we received $23.5 million at closing, which resulted in a gain on sale of equity method investments of $23.0 million. An incremental $5.0 million is payable to us in April 2022, and we could receive up to $7.5 million in total contingent earn-out payments from 2023 to 2025.

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Real Estate Divestiture

On June 28, 2021, we closed on the sale of one of our real estate properties located in Midland, Texas for proceeds of $9.1 million, including closing adjustments, which resulted in a loss on disposal of $0.4 million.

Pecos County Gas Gathering Divestiture

On November 1, 2021, we completed the sale of substantially all of our natural gas gathering assets to Brazos Delaware Gas, LLC, an affiliate of Brazos Midstream, for aggregate total gross potential consideration of $93.0 million, consisting of (i) $83.0 million paid at closing, after customary closing adjustments, (ii) a $5.0 million contingent payment due in 2023 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of Diamondback and its affiliates exceed certain specified thresholds during 2022, and (iii) a $5.0 million contingent payment due in 2024 if the aggregate actual deliveries of gas volumes into the gas gathering system by and/or on behalf of Diamondback and its affiliates exceed certain specified thresholds during 2022 and 2023. The contingent payments will be recorded if and when they become realizable.

See Note 4—Acquisitions and Divestitures and Note 16—Subsequent Events included in the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of these transactions.

Operational Update

Highlights

The following are our significant operating results for the year ended December 31, 2021, as compared with the year ended December 31, 2020:

average crude oil gathering volumes were 79,071 Bbl/d, a decrease of 14% year over year;
average produced water gathering and disposal volumes were 783,259 Bbl/d, a decrease of 5% year over year; and
average sourced water gathering volumes were 268,259 Bbl/d, an increase of 6% year over year.

Pipeline Infrastructure Assets

The following tables provide information regarding our gathering and transportation system as of December 31, 2021 and utilization for the year ended December 31, 2021:
(Miles)(1)
Delaware Basin Midland Basin Permian Total
Crude oil 113  46  159 
Produced water 273  310  583 
Sourced water 27  97  124 
Total 413  453  866 
(Capacity/capability)(1)
Delaware Basin Midland Basin Permian Total Utilization
Crude oil gathering (Bbl/d) 240,000  65,000  305,000  27  %
Produced water gathering and disposal (Bbl/d) 1,330,000  2,134,000  3,464,000  24  %
Sourced water gathering (Bbl/d) 120,000  544,000  664,000  43  %
(1)Does not include any assets of our equity method investment joint ventures.

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Results of Operations for the Year Ended December 31, 2021 and 2020
    
The following table sets forth selected historical operating data for the periods indicated:

Year Ended December 31,
2021 2020
Operating Results: (In thousands, except operating data)
Revenues:
Midstream revenues—related party $ 356,498  $ 379,089 
Midstream revenues—third party 26,893  31,124 
Other revenues—related party 8,909  7,801 
Other revenues—third party 4,041  5,891 
Total revenues 396,341  423,905 
Costs and expenses:
Direct operating expenses 102,925  131,393 
Cost of goods sold (exclusive of depreciation and amortization) 43,470  38,370 
Real estate operating expenses 2,231  2,361 
Depreciation, amortization and accretion 49,196  53,123 
Impairment and abandonments 3,371  918 
General and administrative expenses 21,611  16,367 
(Gain) loss on disposal of assets 4,956  (729)
Total costs and expenses 227,760  241,803 
Income (loss) from operations 168,581  182,102 
Other income (expense):
Interest income (expense), net (32,080) (17,287)
Gain (loss) on sale of equity method investments 23,020  — 
Income (loss) from equity method investments 14,779  (9,881)
Total other income (expense), net 5,719  (27,168)
Net income (loss) before income taxes 174,300  154,934 
Provision for (benefit from) income taxes 10,530  10,229 
Net income (loss) 163,770  144,705 
Less: Net income (loss) attributable to non-controlling interest 126,990  110,014 
Net income (loss) attributable to Rattler Midstream LP $ 36,780  $ 34,691 
Operating Data:
Throughput(1)
Crude oil gathering (Bbl/d) 79,071 92,056
Natural gas gathering (MMBtu/d) 112,130 121,637
Produced water gathering and disposal (Bbl/d) 783,259 821,543
Sourced water gathering (Bbl/d) 268,259 253,907
(1)    Does not include volumes from our equity method investment joint ventures.
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Comparison of the Years Ended December 31, 2021 and 2020

Revenues

Total revenues decreased by $27.6 million to $396.3 million in 2021 compared to $423.9 million in 2020, primarily due to declines in revenue from (i) produced water gathering and disposal of $20.1 million,(ii) crude oil gathering of $4.2 million, and (iii) natural gas gathering of $1.7 million.

The decreases in revenues from produced water gathering and crude oil gathering in 2021 were due to a reduction in volumes transported by Diamondback through the systems on our dedicated acreage. The decrease in revenues from natural gas gathered was due primarily to the sale of the Pecos gas gathering assets in the fourth quarter of 2021.

See Note 3—Revenue from Contacts with Customers in the notes to the consolidated financial statements included elsewhere in this Annual Report for additional discussion of our revenues.

Direct Operating Expenses

Direct operating expenses decreased by $28.5 million to $102.9 million in 2021 compared to $131.4 million in 2020, primarily due to a decline in volumes year over year and a focus on reducing costs. Additionally, we received electricity credits of $3.4 million related to the February 2021 winter storm in the Permian Basin and the sale of the Pecos gas gathering assets resulted in an additional decrease in expenses of approximately $1.5 million.

Cost of Goods Sold

Cost of goods sold (exclusive of depreciation and amortization) increased by $5.1 million to $43.5 million in 2021 compared to $38.4 million in 2020 due to an increase in sourced water volumes transported in the second and third quarters of 2021.

 
Depreciation, Amortization and Accretion

Depreciation, amortization and accretion decreased by $3.9 million to $49.2 million in 2021 compared to $53.1 million in 2020, largely due to the 2020 period including $3.0 million of accelerated depreciation related to the abandonment of certain disposal well assets and $1.1 million of accelerated amortization of in-place lease intangibles for early terminated leases. This reduction was partially offset by further development of existing gathering and compression, transportation and disposals systems which increased our depreciable asset base.

General and Administrative Expenses

General and administrative expenses increased by $5.2 million to $21.6 million in 2021 compared to $16.4 million, for 2020, primarily due to $4.0 million of higher shared service allocations and additional professional service fees attributable to business growth, as well as $1.2 million of additional public company costs incurred.

Interest Expense, Net

Net interest expense increased by $14.8 million to $32.1 million in 2021 compared to $17.3 million for 2020, primarily due to additional interest accrued on the Notes which were issued in July 2020 and bear interest at a rate of 5.625% per annum.

Currently, we expect to incur aggregate future cash interest costs of $112.5 million on our Notes, consisting of approximately $28.1 million due in each of the years from 2022 through 2025.

Gain (loss) on Sale of Equity Method Investments

The gain of $23.0 million on sale of equity method investments in 2021 related to the sale of our interest in Amarillo Rattler. See Note 4—Acquisitions and Divestitures in the notes to the consolidated financial statements included elsewhere in this Annual Report for discussion of the sale.

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Income (Loss) from Equity Method Investments

Income from equity method investments was $14.8 million in 2021 compared to a loss of $9.9 million in 2020, primarily due to the 2020 period including a proportional charge of $15.8 million in goodwill impairment recorded by an investee. The remaining change primarily stemmed from the addition of $5.6 million in income from the WTG joint venture acquired in the fourth quarter of 2021, and a general recovery in the operations of our other equity method investments in 2021 after the oil and gas industry downturn due to the COVID-19 pandemic and other economic factors in 2020. See Note 7—Equity Method Investments in the notes to the consolidated financial statements included elsewhere in this Annual Report for additional discussion.

Liquidity and Capital Resources

Overview of Sources and Uses of Cash

As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our primary sources of liquidity have included cash generated from operations, borrowings under the credit agreement and the issuance of the Notes. Our primary uses of capital have been for additions to property, plant and equipment, contributions to equity method investments, distributions to our unitholders and repurchases of our common units. As of December 31, 2021, we had approximately $425 million of liquidity consisting of $20 million in cash and $405 million available under the Operating Company’s revolving credit facility.

Our working capital requirements are supported by our cash and the revolving credit facility. We believe that cash generated from the sources discussed above will be sufficient to meet our short-term and long-term funding requirements including our capital spending programs, distribution payments, repayment of the Operating Company’s revolving credit facility, repurchase program, expenses under the services and secondment agreement with Diamondback and other amounts that may ultimately be paid in connection with commitments and contingencies. 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. Although we expect that our sources of capital will be adequate to fund our short-term and long-term liquidity requirements, should we require additional capital, the indirect effect of volatile 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 Flows

The following table presents our cash flows for the periods indicated:
  Year Ended December 31,
  2021 2020
(In thousands)
Net cash provided by (used in) operating activities $ 248,100  $ 229,899 
Net cash provided by (used in) investing activities (183,323) (180,809)
Net cash provided by (used in) financing activities (68,807) (35,796)
Net increase (decrease) in cash $ (4,030) $ 13,294 
Operating Activities

Net cash provided by operating activities increased by $18.2 million during the year ended December 31, 2021 compared to the year ended December 31, 2020, primarily due to distributions representing returns on investment from our equity method investments of $34.7 million, a decrease in direct operating expenses of $28.5 million, and an $8.1 million fluctuation in working capital primarily due to the timing of when collections are made on accounts receivable and payments are made on accounts payable and accrued liabilities. These increases in cash flow were partially offset by a $27.6 million decline in revenues, an increase in cash paid for interest of $21.8 million, and less significant increases in cost of goods sold and cash general and administrative costs. See Results of Operations for further discussion of changes in revenue, operating expenses and interest expense and Note 7—Equity Method Investments in the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of distributions.
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Investing Activities

Net cash used in investing activities was $183.3 million for the year ended December 31, 2021 and consisted primarily of (i) a payment of $160.0 million for the Drop Down acquisition, (ii) contributions of $113.6 million to our equity method investments, including the initial investment in the WTG joint venture, and (iii) other capital expenditures of $32.2 million which primarily related to our produced water disposal assets, See 2021 Transactions and Recent Developments for additional discussion of these expenditures.

Cash outflows for investing activities in 2021 were partially offset by proceeds from divestitures of $113.3 million, and $9.1 million in distributions considered to be returns of investment received from certain of our equity method investments prior to placing constructed assets in service.

Net cash used in investing activities was $180.8 million for the year ended December 31, 2020, and primarily related to $136.8 million in capital expenditures and $102.5 million in contributions to our equity method investments. Our capital expenditures consisted of (i) $111.2 million for our produced water disposal assets, (ii) $8.9 million for our natural gas gathering assets, (iii) $8.2 million for our sourced water assets, (iv) $7.9 million for our crude oil gathering assets and (v) $0.6 million for our real estate assets.

Financing Activities

Net cash used in financing activities was $68.8 million during the year ended December 31, 2021, and primarily related to distributions paid to our unitholders of $133.7 million, net payments on the revolving credit facility of $116.0 million and $47.6 million in repurchases of common units under our repurchase program.

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

Capital Resources

The Operating Company’s Revolving Credit Facility

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.
As of December 31, 2021, there was $195.0 million of outstanding borrowings under the Operating Company’s revolving credit facility. The weighted average interest rate on borrowings under the credit agreement was 1.41% for the year ended December 31, 2021. The revolving credit facility matures in 2024.
As of December 31, 2021, the Operating Company was in compliance and expects to be in compliance with all financial maintenance covenants under the credit agreement.
For additional information regarding the revolving credit facility and outstanding debt, see Note 8—Debt in the notes to the consolidated financial statements included elsewhere in this Annual Report.

Capital Requirements

2022 Capital Budget

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.
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We estimate that our total capital expenditures related to midstream assets for 2022 will be between $80 million and $100 million. Our estimated capital expenditures do not include our anticipated total capital commitments related to our equity method investments of approximately $10 million to $15 million. We also estimate we will receive $45 million to $55 million in distributions related to our equity method investments. However, this range could change due to the continued impact, either directly or indirectly, of the COVID-19 pandemic or volatility in crude oil prices on our business.

As of February 18, 2022, we own equity interests in the EPIC, Gray Oak, Wink to Webster, OMOG, WTG Midstream and BANGL joint ventures. Each of these joint ventures is accounted for using the equity method. The following table sets forth our cumulative capital contributions and anticipated future capital commitment for each of our equity method investment interests:
Ownership Interest Acquisition Date Cumulative Capital Contributions to Date Anticipated Future Capital Commitment
(In thousands)
EPIC Crude Holdings, LP 10  % February 1, 2019 $ 138,034  $ 2,620 
Gray Oak Pipeline, LLC 10  % February 15, 2019 $ 142,096  $ — 
Wink to Webster Pipeline LLC % July 30, 2019 $ 89,453  $ 18,547 
OMOG JV LLC 60  % October 1, 2019 $ 218,555  $ — 
Remuda Midstream Holdings LLC 25  % October 5, 2021 $ 104,502  $ 2,012 
BANGL, LLC 10  % January 19, 2022 $ 22,150  $ 5,000 

See Note 7—Equity Method Investments and Note 16—Subsequent Events in the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion regarding our equity method investments.

Volume Commitment Agreement

As discussed in Note 15—Commitments and Contingencies in the notes to the consolidated financial statements included elsewhere in this Annual Report, the Partnership has a water services agreement for produced water disposal services through 2034. The aggregate remaining minimum commitment is $51.1 million, with approximately $4.6 million due in each of the years from 2022 through 2025, $3.7 million due in 2026 and the remainder due in the years thereafter.

Common Unit Repurchase Program

In October 2021, the board of directors of our General Partner approved an increase of the authorization of our common unit repurchase program to $150.0 million of the Partnership’s outstanding common units and extended the program indefinitely. During the year ended December 31, 2021, we repurchased approximately $47.6 million of common units under the repurchase program. As of December 31, 2021, $87.7 million remained available for future repurchases of our common units under our program. See Note 10—Unitholders' Equity and Distributions in the notes to the consolidated financial statements included elsewhere in this Annual Report for further discussion of the common unit repurchase program.

Cash Distributions

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 16, 2022, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2021 of $0.30 per common unit, payable on March 14, 2022, to common unitholders of record at the close of business on March 7, 2022.

Critical Accounting 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.

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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) accounting for equity method investments and (ii) estimate of income taxes.

We consider the following to be our most critical accounting estimates and have reviewed these critical accounting estimates with the Audit Committee of our Board of Directors.

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

Equity Method Investments

We review our investments to determine if a loss in value which is other than a temporary decline has occurred when events indicate the carrying value of the investment may not be recoverable. When such indicators are present and the decline in value is considered to be other than temporary the carrying value of the investment is written down to its fair value. In making the determination as to whether a decline is other than temporary, we consider such factors as the length of time the fair value is below the investor’s carrying value, current expected performance relative to expected performance when we initially invested in the investee, the investee’s performance relative to peers, the industry’s performance relative to the economy, regulatory actions, the investee’s ability to refinance its debt in future periods, and estimated discounted cash flows for the investment, among other factors. Such analysis requires management to make significant estimates and assumptions and apply judgment based on historical experience. If such a loss has occurred, we recognize an impairment provision and do not increase the cost basis of the investment for subsequent recoveries in fair value. A reduction of the carrying value of equity method investments would represent a Level 3 fair value measurement.

Based on indicators present at December 31, 2021, we reviewed our investment in EPIC for impairment utilizing an estimate of fair value calculated in a discounted cash flow model in accordance with the income approach in ASC 820— Fair Value Measurement. The discounted cash flow model incorporates our expectations of EPIC’s future revenue, operating expenses, and non-operating expenses including debt service costs based on expected future debt levels, and discounts the projected cash flows to the current fair value using an estimated weighted average cost of capital at the date of valuation. The resulting fair value was below the current carrying value of the EPIC investment. However, based on our consideration of the factors noted above, among others, we determined the decline in fair value is temporary and, thus, no impairment expense was recorded at December 31, 2021. Key factors impacting our conclusion that the decline in fair value is temporary include forecasted increases in asset utilization based on published industry data, reported production increases by major producers transporting production on EPIC’s pipeline and a determination that EPIC will refinance its maturing debt obligations by 2026. Based on the subjectivity of the estimates included in the various scenarios of our fair value estimate, should our analysis of the factors above change in future periods, we could recognize an other than temporary impairment. The amount of future impairment, if any, will be based on updated assumptions at that time. If our estimate of fair value changes or if our conclusion regarding the temporary nature of any decline in fair value changes, it could have a material impact on our future consolidated financial statements and results of operations.

Income Taxes

We are 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, and are often based on assumptions that are subject to a significant amount of judgment. These assumptions and judgments are reviewed and adjusted by management as facts and circumstances change. 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
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considering all positive and negative evidence available concerning the realizability of our deferred tax assets. As of December 31, 2021, no such valuation allowance was determined to be necessary against our deferred tax asset of $62.4 million. However, any changes in the positive or negative evidence evaluated, including a change in our projected future income or losses due to a decline in economic conditions, or other estimates and considerations, could result in a material impact to our deferred tax assets and income tax expense.

See Note 2—Summary of Significant Accounting Policies in the notes to the consolidated financial statements included elsewhere in this Annual Report for a full listing of our significant accounting policies.

Recent Accounting Pronouncements

See Note 2—Summary of Significant Accounting Policies in the notes to the consolidated financial statements included elsewhere in this Annual Report for recent accounting pronouncements and accounting policies not yet adopted, if any.

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 an 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 NGLs 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.
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As of December 31, 2021, we had $195.0 million of outstanding borrowings and $405.0 million available for future borrowings under the credit agreement. The weighted average interest rate on borrowings under the credit agreement was 1.41% for the year ended December 31, 2021.

 
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.

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, 2021, 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, 2021, our disclosure controls and procedures are effective.

Changes in Internal Control over Financial Reporting. In July 2021, we implemented an enterprise resource planning system covering various financial and accounting processes. As a result of this implementation, certain internal controls over financial reporting have been automated, modified or implemented to address the new environment associated with the implementation of this system. We believe we have maintained appropriate internal control over financial reporting during the implementation and believe this new system will strengthen our internal control system. However, there are inherent risks in implementing any new system, and we will continue to evaluate these control changes as part of our assessment of 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, 2021 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, 2021.

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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, 2022. 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.
Name Age Position With Our General Partner
Travis D. Stice 60 Chief Executive Officer and Director
Kaes Van't Hof 35 President and Director
Teresa L. Dick 52 Chief Financial Officer, Executive Vice President and Assistant Secretary
Matt Zmigrosky 43 Executive Vice President, General Counsel and Secretary
Steven E. West 61 Chairman of the Board
Laurie H. Argo 49 Director
Arturo Vivar 59 Director

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.

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
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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 and member of the audit and conflicts committee. Ms. Argo served as a director and member of the audit committee of EVRAZ plc, a multinational, vertically integrated steel making and mining company from August 2018 through June 2021, with additional compensation and stakeholder engagement committee memberships from 2020-2021. 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 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
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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 25 years of experience in the energy industry, continues to perform consulting services for clients in the energy industry and is a member of the National Association of Corporate Directors (NACD).

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 30 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 and Diversity

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, disclose details regarding board diversity or 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.

The board of directors of our General Partner has established an independent audit committee and a conflicts committee, discussed in more detail below, and has diverse representatives on its board, including a female director.

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 a director of Diamondback. Mr. West was also the Chairman of the Board of Diamondback from October 2012 to February 2022, when he was succeeded in that role by Mr. Stice. Our General Partner’s board of directors has determined that Mr. West’s roles of Chairman of the Board of directors of our General Partner and a director 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.

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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 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 2021, the board of directors of our General Partner met five 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 2021.

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, of which Mr. West serves as the Chairman. 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.

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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.

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 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
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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 2021 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 2022 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 certain of the tables included in Diamondback’s 2022 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 2021 and 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
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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.

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. The number of phantom units awarded is calculated by dividing $100,000 by the average closing price of our common units for the five trading days immediately preceding the date of grant. The awards vest on the first anniversary of the grate date. 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 2021 for their services on the board:
Name Fees Earned or Paid in cash(a) Unit Awards(b) Total
Steven E. West(c)(d)
$ 75,000  99,965  $ 174,965 
Laurie H. Argo(c)(d)
$ 75,000  99,965  $ 174,965 
Arturo Vivar(c)(d)
$ 75,000  99,965  $ 174,965 
(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.
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(c)Each of Ms. Argo and Messrs. West and Vivar received a grant of 11,011 phantom units on July 10, 2020, which vested and settled 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.
(d)Each of Ms. Argo and Messrs. West and Vivar received a grant of 9,256 phantom units on July 12, 2021, which will vest and settle on July 12, 2022, pursuant to the LTIP, with each unit having a grant date fair value of $10.80. 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 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 2022 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” included elsewhere in this Annual Report 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” above and “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” included elsewhere in this Annual Report for more information about this arrangement. For an analysis of any risks arising from Diamondback’s compensation policies and practices, see Diamondback’s 2022 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.

 
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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, 2022 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)
118,419 *
Kaes Van’t Hof(3)
268,256 *
Teresa L. Dick(4)
20,749 *
Matt Zmigrosky(5)
8,568 *
Laurie H. Argo(6)
17,225 *
Arturo Vivar(6)
30,975 *
Steven E. West(6)
27,100 *
All directors and executive officers of our General Partner as a group (7 persons) 491,292 *
*    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, 2022 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, 2022 are all deemed to be beneficially owned. These common units, however, are not deemed outstanding for the purpose of computing the percentage ownership of each other person. The percentage of common units beneficially owned is based on 38,139,805 common units outstanding as of January 31, 2022. 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, 2022 or within 60 days of January 31, 2022. 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 68,572 phantom units, that are scheduled to vest in three remaining equal installments beginning on May 28, 2022.
(3)Excludes 685,715 phantom units, that are scheduled to vest in three equal installments beginning on May 28, 2022.
(4)Excludes 34,286 phantom units, that are scheduled to vest in three equal installments beginning on May 28, 2022.
(5)Excludes 13,715 phantom units, that are scheduled to vest in three equal installments beginning on May 28, 2022.
(6)Excludes 9,256 phantom units, that are scheduled to vest on July 12, 2022.


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The following table sets forth, as of January 31, 2022, 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 Owner Amount and Nature of
Beneficial Ownership
Percentage of
Class
Travis D. Stice(2)
403,324 *
Kaes Van’t Hof(3)
45,615 *
Teresa L. Dick(4)
49,535 *
Matt Zmigrosky(5)
14,175 *
Laurie H. Argo
Arturo Vivar
Steven E. West(6)
3,756 *
All directors and executive officers as a group (7 persons) 516,405 *
*    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, 2022 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, 2022, 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 177,412,057 shares of common stock outstanding as of January 31, 2022. 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, 2022 or within 60 days of January 31, 2022. 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 26,325 restricted stock units, that are scheduled to vest on March 1, 2022. Excludes 11,499 restricted stock units, that are scheduled to vest on March 1, 2023. Also excludes (i) 49,436 performance-based restricted stock units awarded on March 1, 2019, that vested effective December 31, 2021 (representing 100% 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, 2021 by Diamondback’s compensation committee, (ii) 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 and (iii) 51,748 performance-based restricted stock units awarded to Mr. Stice on March 1, 2021, 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, 2023.
(3)Includes 12,955 restricted stock units, that are scheduled to vest on March 1, 2022. Excludes (i) 6,038 restricted stock units, that are scheduled to vest on March 1, 2023, (ii) 8,790 restricted stock units, that are scheduled to vest in five equal annual installments beginning on March 1, 2025, (iii) 23,070 performance-based restricted stock units awarded on March 1, 2019, that vested effective December 31, 2021 (representing 100% 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, 2021 by Diamondback’s compensation committee, (iv) 13,183 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2019 (representing 100% vesting of the originally reported amount) based upon final determination upon certification of certain stockholders return performance conditions relative to Diamondback’s peer group during the three-year performance period ended on December 31, 2021, that are scheduled to vest in five equal installments beginning on March 1, 2025, (v) 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 and (vi) 27,168 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2021, 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, 2023.
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(4)Includes 7,403 restricted stock units, that are scheduled to vest on March 1, 2022. Excludes 3,450 restricted stock units, that are scheduled to vest on March 1, 2023. Also excludes (i) 13,183 performance-based restricted stock units awarded to Ms. Dick on March 1, 2019, that vested effective December 31, 2021 (representing 100% 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, 2021 by Diamondback’s compensation committee, (ii) 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 and (iii) 15,524 performance-based restricted stock units awarded to Ms. Dick on March 1, 2021, 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, 2023.
(5)Includes 5,922 restricted stock units, that are scheduled to vest on March 1, 2022. Excludes 2,760 restricted stock units, that are scheduled to vest on March 1, 2023. Also excludes (i) 10,546 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2019, that vested effective December 31, 2021 (representing 100% 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, 2021 by Diamondback’s compensation committee 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 and (iii) 12,420 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2021, 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, 2023.
(6)Excludes 2,435 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 2022 annual meeting of stockholders of Diamondback.

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 14, 2022 by each unitholder known by us to beneficially own 5% or more of our common units or Class B units.
Common Units Class 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  %
Cardinal Capital Management, LLC(3)
      4 Greenwich Office Park
      Greenwich, CT 06831
3,199,594  8.4  %
ClearBridge Investments, LLC (4)
      620 8th Avenue
      New York, NY 10018
3,086,248  8.1  % —  — 
Capital World Investors (5)
      333 South Hope Street
      Los Angeles, CA 90071
2,859,750  7.5  %
Macquarie Group Limited (6)
      50 Martin Place
      Sydney, New South Wales, Australia
2,269,273  6.0  %
Kayne Anderson Capital Advisors, LP (7)
      1800 Avenue of the Stars, Third Floor
      Los Angeles, CA 90067
2,065,968  5.4  % —  — 
(1)Beneficial ownership is determined in accordance with SEC rules. The percentage of common units beneficially owned is based on 38,139,805 common units outstanding as of January 31, 2022. 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.
53

(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 Diamondback E&P LLC, its indirect wholly owned subsidiary (“Diamondback E&P”). The 107,815,152 Class B units, together with the same number of units of the Operating Company (each, an “Operating Company unit”), held by Diamondback E&P, are exchangeable from time to time, at Diamondback’s discretion, for common units (that is, one Operating Company 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 Diamondback E&P, 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 Diamondback E&P.
(3)Based solely on Schedule 13G filed with the SEC on February 14, 2022 by Cardinal Capital Management, LLC (“Cardinal Capital”). Cardinal Capital reported beneficial ownership of 3,199,594 common units, as well as sole voting power over 2,730,898 common units and sole dispositive power over 3,199,594 common units. No shared voting power and no shared dispositive power was reported by Cardinal Capital.
(4)Based solely on Schedule 13G/A filed with the SEC on February 9, 2022 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, 3,086,248 common units. No shared voting power and no shared dispositive power was reported by ClearBridge.
(5)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.
(6)Based solely on Schedule 13G filed with the SEC on February 11, 2022 by Macquarie Group Limited on behalf of itself and Macquarie Management Holdings Inc, Macquarie Investment Management Business Trust and Ivy Investment Management Company. As of December 31, 2021, Macquarie Management Holdings Inc had sole voting and dispositive power over 2,268,849 shares, Macquarie Investment Management Business Trust had sole voting and dispositive power over 2,268,849 shares, and Ivy Investment Management Company had shared voting and dispositive power over 424 shares. Macquarie Group Limited is deemed to beneficially own 2,269,273 shares due to its ownership of the entities above. The address of Macquarie Bank Limited is 50 Martin Place, Sydney, New South Wales, Australia. The address of Macquarie Management Holdings Inc. and Macquarie Investment Management Business Trust is 2005 Market Street, Philadelphia, PA 19103. The address of Ivy Investment Management Company is 6301 Glenwood St Overland Park, KS 66202.
(7)Based solely on Schedule 13G jointly filed with the SEC on February 3, 2022 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, 2,065,968 common units. Richard A. Kayne reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,065,968 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, 2021:
Plan Category Number 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)
1,737,525  —  12,696,146 
(1)This information relates to our LTIP, which our General Partner adopted at the closing of the IPO in May 2019. See “Item 11. Executive Compensation–Long-Term Incentive Plan included elsewhere in this Annual Report for a description of the LTIP.

54

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, 2021 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 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, 2021, Mr. Stice held 68,572 unvested phantom units granted under the LTIP, all which are scheduled to vest in three equal installments beginning on May 28, 2022, and had a value of $780,349 as of December 31, 2021.
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, 2021, Mr. Van’t Hof held 685,715 unvested phantom units granted under the LTIP, all of which are scheduled to vest in three equal annual installments beginning on May 28, 2022, and had a value of $7,803,437 as of December 31, 2021; Ms. Dick held 34,286 unvested phantom units granted under the LTIP, all of which are scheduled to vest in three equal annual installments beginning on May 28, 2022, and had a value of $390,175 as of December 31, 2021; and Mr. Zmigrosky held 13,715 unvested phantom units granted under the LTIP, all of which are scheduled to vest in three equal annual installments beginning on May 28, 2022, and had an aggregate value of $156,077 as of December 31, 2021. No other executive officers of our General Partner held equity awards under the LTIP as of December 31, 2021.

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 Acreage Dedications. 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 Acreage Dedications. 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 Acreage Dedications. 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 Acreage Dedications. On December 1, 2021, the Partnership further amended its commercial agreements covering produced water gathering and disposal and sourced water gathering services to add certain Diamondback leasehold acreage to the Rattler dedication.

55

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 the 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” included elsewhere in this Annual Report for more details regarding the reimbursement provisions of our partnership agreement.

Services and Secondment Agreement

As amended on December 22, 2021, the Holding Company was added as a party to the services and secondment agreement to support the Holding Company’s role as the managing member of the Operating Company. 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 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 Operating Company 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, 2021, Diamondback received distributions from the Operating Company in the aggregate amount of $97.1 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 the Operating Company 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
56

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, 2021.
Year Ended December 31, 2021
(In thousands)
Revenues Generated under Agreements and Transactions with Affiliates
Produced water gathering and disposal commercial agreement $ 263,833 
Sourced water gathering commercial agreement $ 65,503 
Natural gas gathering commercial agreement $ 18,827 
Crude oil gathering commercial agreement $ 8,104 
Surface revenue transactions $ 231 
Fasken Center agreement $ 8,910 
Expenses Incurred under Agreements with Affiliates
Services and secondment agreement $ 7,657 
Partnership agreement $ 738 
Tax sharing agreement $ 1,319 

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.

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, 2021 and 2020. 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, 2021 and 2020 were approved by the audit committee.

57


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,
2021 2020
(In thousands)
Audit fees(1)
$ 402  $ 365 
Audit-related fees(2)
—  66 
Tax fees(3)
—  — 
All other fees(4)
—  — 
Total $ 402  $ 431 
(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.
58

PART IV

ITEM 15.     EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Documents included in this report:
1. Financial Statements
F-1
F-2
F-3
F-4
F-5
F-7
F-8
2. Financial Statement Schedules
Financial statement schedules have been omitted because they are either not required, not applicable or the information required to be presented is included in our consolidated financial statements and related notes.

3. Exhibits
Exhibit Number
Description
2.1#
2.2#
2.3#
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
4.1
59

3. Exhibits
Exhibit Number
Description
4.2
4.3
4.4*
4.5*
10.1^
10.2
10.3^
10.4^
10.5^
10.6^
10.7^
10.8^
10.9^
10.10
10.11
10.12
60

3. Exhibits
Exhibit Number
Description
10.13
10.14
10.15+
10.16+
10.17+
10.18+
10.19
10.20
10.21
21.1*
23.1*
31.1*
31.2*
32.1++
101
The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2021, formatted in Inline XBRL: (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income (iv) Consolidated Statement of Changes in Unitholders’ Equity, (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements.
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*
Filed herewith.
#
The schedules (or similar attachments) referenced in this agreement have been omitted in accordance with Item 601(b)(2) of Regulation S-K. A copy of any omitted schedule (or similar attachment) will be furnished supplementally to the Securities and Exchange Commission upon request.
^
Confidential treatment has been requested for certain portions thereof pursuant to a Confidential Treatment Request filed with the Securities and Exchange Commission. Such provisions have been filed separately with the Securities and Exchange Commission.
+
Management contract, compensatory plan or arrangement.
++
The certifications attached as Exhibit 32.1 accompany this Annual Report on Form 10-K pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.

ITEM 16.     FORM 10-K SUMMARY

None.

61

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this Annual Report to be signed on its behalf by the undersigned thereunto duly authorized.
RATTLER MIDSTREAM LP
Date: February 24, 2022
By: RATTLER MIDSTREAM GP LLC,
its General Partner
By: /s/ Travis D. Stice
Name: Travis D. Stice
Title: Chief Executive Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ Travis D. Stice Chief Executive Officer and Director February 24, 2022
Travis D. Stice (Principal Executive Officer)
/s/ Teresa L. Dick Chief Financial Officer February 24, 2022
Teresa L. Dick (Principal Financial and Accounting Officer)
/s/ Kaes Van’t Hof President and Director February 24, 2022
Kaes Van’t Hof
/s/ Laurie H. Argo Director February 24, 2022
Laurie H. Argo
/s/ Arturo Vivar Director February 24, 2022
Arturo Vivar
/s/ Steven E. West Director February 24, 2022
Steven E. West

S-1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Unitholders
Rattler Midstream LP

Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Rattler Midstream LP (a Delaware limited partnership) and subsidiaries (the “Company”) as of December 31, 2021 and 2020, the related consolidated statements of operations, statements of comprehensive income, changes in unitholders’ equity, and cash flows for each of the three years in the period ended December 31, 2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity with accounting principles generally accepted in the United States of America.

Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2018.
Oklahoma City, Oklahoma
February 24, 2022

F-1

Rattler Midstream LP
Consolidated Balance Sheets

  December 31, December 31,
  2021 2020
  (In thousands)
Assets    
Current assets:    
Cash $ 19,897  $ 23,927 
Accounts receivable—related party 58,154  57,447 
Accounts receivable—third party, net 9,415  5,658 
Sourced water inventory 13,081  10,108 
Other current assets 1,181  1,127 
Total current assets 101,728  98,267 
Property, plant and equipment:    
Land 98,645  85,826 
Property, plant and equipment 1,075,405  1,012,777 
Accumulated depreciation, amortization and accretion (121,507) (100,728)
Property, plant and equipment, net 1,052,543  997,875 
Right of use assets —  574 
Equity method investments 612,541  532,927 
Real estate assets, net 84,609  96,687 
Intangible lease assets, net 3,650  4,262 
Deferred tax asset 62,356  73,264 
Other assets 3,708  4,732 
Total assets $ 1,921,135  $ 1,808,588 
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable and accrued liabilities $ 48,267  $ 42,647 
Taxes payable 603  192 
Short-term lease liability —  574 
Asset retirement obligations 79  35 
Total current liabilities 48,949  43,448 
Long-term debt 687,956  569,947 
Asset retirement obligations 16,911  15,093 
Total liabilities 753,816  628,488 
Commitments and contingencies (Note 15)
   
Unitholders’ equity:
General Partner—Diamondback 819  899 
Common units—public (38,356,771 units issued and outstanding as of December 31, 2021 and 42,356,637 units issued and outstanding as of December 31, 2020)
350,230  385,189 
Class B units—Diamondback (107,815,152 units issued and outstanding as of December 31, 2021 and as of December 31, 2020)
819  899 
Accumulated other comprehensive income (loss) 10  (123)
Total Rattler Midstream LP unitholders’ equity 351,878  386,864 
Non-controlling interest 815,441  793,638 
Non-controlling interest in accumulated other comprehensive income (loss) —  (402)
Total equity 1,167,319  1,180,100 
Total liabilities and unitholders’ equity $ 1,921,135  1,808,588 






The accompanying notes are an integral part of these consolidated financial statements.
F-2

Rattler Midstream LP
Consolidated Statements of Operations

Year Ended December 31,
2021 2020 2019
(In thousands, expect per unit amounts)
Revenues:  
Midstream revenues—related party $ 356,498  $ 379,089  $ 409,120 
Midstream revenues—third party 26,893  31,124  24,324 
Other revenues—related party 8,909  7,801  5,150 
Other revenues—third party 4,041  5,891  9,079 
Total revenues 396,341  423,905  447,673 
Costs and expenses:    
Direct operating expenses 102,925  131,393  106,311 
Cost of goods sold (exclusive of depreciation and amortization) 43,470  38,370  62,856 
Real estate operating expenses 2,231  2,361  2,643 
Depreciation, amortization and accretion 49,196  53,123  42,336 
Impairment and abandonments 3,371  918  — 
General and administrative expenses 21,611  16,367  12,663 
(Gain) loss on disposal of assets 4,956  (729) 1,524 
Total costs and expenses 227,760