RATTLER MIDSTREAM LP - Annual Report: 2019 (Form 10-K)

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, 2019



☐	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)

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 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 $844.6 million on June 28, 2019, 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 14, 2020, 43,700,000 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, 2019

TABLE OF CONTENTS



	Page
Glossary of Oil and Natural Gas Terms	ii
Glossary of Certain Other Terms	iv
Cautionary Statement Regarding Forward-Looking Statements	v

PART I
Items 1 and 2. Business and Properties	1
Item 1A. Risk Factors	16
Item 1B. Unresolved Staff Comments	40
Item 3. Legal Proceedings	40
Item 4. Mine Safety Disclosures	40

PART II
Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	41
Item 6. Selected Financial Data	42
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations	45
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	62
Item 8. Financial Statements and Supplementary Data	63
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63
Item 9A. Controls and Procedures	63
Item 9B. Other Information	64

PART III
Item 10. Directors, Executive Officers and Corporate Governance	64
Item 11. Executive Compensation	68
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	72
Item 13. Certain Relationships and Related Transactions, and Director Independence	76
Item 14. Principal Accountant Fees and Services	79

PART IV
Item 15. Exhibits and Financial Statement Schedules	81
Item 16. Form 10-K Summary	85
Signatures	S-1

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GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a glossary of certain oil and natural gas industry terms used in this Annual Report on Form 10-K (this “Annual Report” or this “report”):



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

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

iii

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GLOSSARY OF CERTAIN OTHER TERMS

The following is a glossary of certain other terms used in this report:



Delaware Act	Delaware Revised Uniform Limited Partnership Act.
Diamondback	Diamondback Energy, Inc., a Delaware corporation, and its subsidiaries other than the Partnership and its subsidiaries (including the Operating Company).
DOT	The U.S. Department of Transportation.
EPA	U.S. Environmental Protection Agency.
Exchange Act	The Securities Exchange Act of 1934, as amended.
FERC	Federal Energy Regulatory Commission.
GAAP	Accounting principles generally accepted in the United States.
General partner	Rattler Midstream GP LLC, a Delaware limited liability company; the general partner of the Partnership and a wholly owned subsidiary of Diamondback.
GHG	Greenhouse gases.
IPO	The Partnership’s initial public offering.
IRS	Internal Revenue Service.
JOBS Act	The Jumpstart Our Business Startups Act of 2012.
Nasdaq	The Nasdaq Global Select Market.
Operating Company or OpCo	Rattler Midstream Operating LLC, a Delaware limited liability company and a consolidated subsidiary of the Partnership.
OSHA	Federal Occupational Safety and Health Act.
Partnership	Rattler Midstream LP, a Delaware limited partnership.
Partnership agreement	The first amended and restated agreement of limited partnership of Rattler Midstream LP, dated May 28, 2019.
Predecessor	The Operating Company, prior to May 28, 2019 for accounting purposes.
SEC	Securities and Exchange Commission.
Securities Act	The Securities Act of 1933, as amended.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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

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


•	Diamondback’s ability to meet its drilling and development plans on a timely basis or at all;


•	changes in general economic conditions;


•	competitive conditions in our industry;


•	actions taken by third party operators, gatherers, processors and transporters;


•	the demand for and costs of conducting midstream infrastructure services;


•	our ability to successfully implement our business plan;


•	our ability to complete internal growth projects on time and on budget;


•	our ability to identify, complete and effectively integrate acquisitions into our operations;


•	our ability to achieve anticipated synergies, system optionality and accretion associated with acquisitions;


•	the results of our investments in joint ventures;


•	the price and availability of debt and equity financing;


•	the availability and price of crude oil and natural gas to the consumer compared to the price of alternative and competing fuels;


•	competition from the same and alternative energy sources;


•	energy efficiency and technology trends;


•	operating hazards and other risks incidental to our midstream services;


•	natural disasters, weather-related delays, casualty losses and other matters beyond our control;


•	interest rates;


•	labor relations;


•	defaults by Diamondback under our commercial agreements;


•	our lack of asset and geographic diversification;


•	changes in availability and cost of capital;

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•	increases in our tax liability;


•	the effect of existing and future laws and government regulations;


•	terrorist attacks or cyber threats; and


•	the effects of future litigation.

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

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PART I

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

ITEMS 1 AND 2. BUSINESS AND PROPERTIES

Overview

We are a growth-oriented Delaware limited partnership formed by Diamondback on July 27, 2018 to own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin, one of the most prolific oil producing areas in the world. We have elected to be treated as a corporation for U.S. federal income tax purposes. Our operations are conducted through, and our operating assets are owned by, the Operating Company, in which we directly own a 29% controlling membership interest as of December 31, 2019. Our assets and operations are reported in two operating business segments: (i) midstream services and (ii) real estate operations.

We provide crude oil, natural gas and water-related midstream services (including water sourcing and transportation and produced water gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of December 31, 2019, our midstream infrastructure assets include 867 miles of pipeline across the Midland and Delaware Basins with approximately 236,000 Bbl/d of crude oil gathering capacity, 135,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering capacity, 3.3 MMBbl/d of produced water disposal capacity and 575,000 Bbl/d of sourced water gathering capacity. In addition to our midstream infrastructure assets, we own equity interests in three long-haul crude oil pipelines, which, upon completion, will 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 acreage dedications from Diamondback. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and produced water disposal capabilities.

Our general partner’s management team consists of members of the management teams of Diamondback and the general partner of Viper Energy Partners LP, or Viper. We believe that our relationship with Diamondback and our common strategic and operational interests provide the optimal platform to pursue a balanced plan for future growth that benefits all unitholders equally.

We are Diamondback’s primary provider of midstream gathering and water-related services. We have 15-year acreage dedications, which we refer to as the Acreage Dedications, from Diamondback spanning approximately 397,000 gross acres on Diamondback’s core leasehold in the Permian (approximately 210,000 gross acres in the Midland Basin and approximately 187,000 gross acres in the Delaware Basin). In this Annual Report, we refer to the acreage subject to the Acreage Dedications as the Dedicated Acreage. We entered into commercial agreements with Diamondback in June 2018, effective as of January 1, 2018, that have initial terms ending in 2034. In addition, we own equity interests in companies that own long-haul pipelines, gathering and processing facilities and related infrastructure that have commercial agreements, including acreage dedications, with Diamondback.

IPO

Prior to the closing on May 28, 2019 of our IPO of common units representing limited partner interests, Diamondback owned all of the general and limited partner interests in our Predecessor. On May 22, 2019, we priced 38,000,000 common units in our IPO at a price of $17.50 per unit, and on May 23, 2019 our common units began trading on the Nasdaq Global Select Market under the symbol “RTLR”. On May 30, 2019, the underwriters purchased an additional 5,700,000 common units following the exercise in full of their over-allotment option. We received aggregate net proceeds of $719.4 million from the sale of these common units, after deducting the underwriting discount and offering expenses.

At the closing of our IPO, we (i) issued to Diamondback 107,815,152 Class B units representing an aggregate 71% voting limited partner interest in us in exchange for a $1.0 million cash contribution from Diamondback, (ii) issued a general partner interest in us to our general partner in exchange for a $1.0 million cash contribution from our general partner, and (iii) caused the Operating Company to make a distribution of approximately $726.5 million to Diamondback. Diamondback, as the holder of the

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Class B units, and our general partner, as the holder of our general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1.0 million capital contributions, payable quarterly.

Our Assets

As of December 31, 2019, we own and operate 867 miles of crude oil gathering pipelines, natural gas gathering pipelines and a fully integrated water system on acreage that overlays Diamondback’s seven core Midland and Delaware Basin development areas. Our water system obtains and distributes sourced water for use in drilling and completion operations and collects flowback and produced water, which we refer to collectively as produced water, for recycling and disposal.

In February 2019, we acquired a 10% equity interest in each of the EPIC pipeline and the Gray Oak pipeline joint ventures, and in July 2019, we acquired a 4% equity interest in the Wink to Webster pipeline joint venture. Once these pipelines are operational, our equity interests in the EPIC, Gray Oak and Wink to Webster joint ventures are expected to provide us with a steady, oil-weighted cash flow stream. Each of the EPIC and Gray Oak pipelines began interim operations in the second half of 2019, and we expect that both will begin full commercial operations in the second quarter of 2020. The Wink to Webster pipeline is expected to begin commercial operations in the first half of 2021. These pipelines will also provide Diamondback with long-term long-haul transportation for a majority of its Delaware and Midland Basin crude oil production.

In October 2019, we acquired a 60% equity interest in OMOG JV LLC, a newly formed joint venture entity that in November 2019 acquired Reliance Gathering, LLC, which owns and operates over 230 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 160,000 gross acres in Northern Midland Basin are dedicated to the system under long-term, fixed-fee agreements, some of which benefit from minimum volume commitments.

In December 2019, we acquired a 50% equity interest in Amarillo Rattler, LLC, a joint venture that currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. Amarillo Rattler also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. We anticipate that the new processing plant will commence full commercial operations in the middle of 2021. Diamondback has contracted for 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with the joint venture in exchange for Diamondback’s dedication of certain leasehold interests to that agreement.

The transportation of water and hydrocarbon volumes away from the producing wellhead is paramount to ensuring the efficient operations of a crude oil or natural gas well. To facilitate this transportation, our midstream infrastructure was built to include a network of gathering pipelines that collect and transport crude oil, natural gas, sourced water and produced water from Diamondback’s operations in the Midland and Delaware Basins. These assets are predominately located in Pecos, Reeves, Ward, Loving, Midland, Howard, Andrews, Martin and Glasscock Counties and have a total of approximately 236,000 Bbl/d of crude oil gathering capacity (42% utilized), 150,000 Mcf/d of natural gas gathering capacity (56% utilized), 135,000 Mcf/d of natural gas compression capability (70% utilized), 3,308,800 Bbl/d of produced water disposal capacity (27% utilized) and 575,000 Bbl/d of sourced water gathering capacity (83% utilized) as of December 31, 2019 (with capacity utilization percentages reflecting fourth quarter 2019 operations).

Crude oil and natural gas gathering and transportation assets

As of December 31, 2019, excluding the assets of our joint ventures, our crude oil and natural gas gathering system covers approximately 296 miles. As of December 31, 2019, excluding the assets of our joint ventures, we have 148 miles of crude oil pipelines, 236,000 Bbl/d of crude oil throughput capacity, 89,000 Bbl of crude oil storage, 148 miles of natural gas pipelines, 150,000 Mcf/d of natural gas gathering capacity and 135,000 Mcf/d of natural gas compression capability. Our crude oil and natural gas gathering and transportation system is purpose built with firm capacity on intermediary pipelines providing connections to long-haul pipelines that terminate on the Texas Gulf Coast. Our crude oil and natural gas gathered volumes, excluding volumes gathered by our joint ventures, averaged 99.4 MBoe/d for the year ended December 31, 2019.

In addition, we own a 10% equity interest in each of the EPIC pipeline and the Gray Oak pipeline joint ventures, a 4% equity interest in the Wink to Webster pipeline joint venture, a 60% equity interest in the OMOG joint venture and a 50% interest in the Amarillo Rattler joint venture, as discussed above.

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Produced water gathering and disposal assets

Crude oil and natural gas cannot be produced without significant produced water transport and disposal capacity given the high water volumes produced alongside the hydrocarbons. At the well site, crude oil and produced water are separated to extract the crude oil for sale and the produced water for proper disposal and recycling. We own strategically located produced water gathering pipeline systems spanning a total of 474 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, 2019, we have a total of 148 produced water disposal wells with an aggregate capacity of 3.3 MMBbl/d located across the Midland and Delaware Basins. Diamondback has instituted a program in its operations to use treated water for 10% to 30% of the water used during completion operations, which may be between 5,500 and 16,500 Bbl/d per completion crew operating in each field, as Diamondback traditionally uses 55,000 Bbl/d per completion crew. We have and expect to continue to realize increased margins for produced water disposal as a result of this recycling program.

Water sourcing and distribution assets

Our water sourcing and distribution system, with storage capacity of 56 MMBbl, is critical to Diamondback’s completion operations, and distributes water from sourced water wells from the Capitan Reef formation, Edwards-Trinity, Pecos Alluvium and Rustler aquifers in the Permian. Our sourced water system consists of a combination of permanent buried pipelines, portable surface pipelines and sourced water storage facilities, as well as pumping stations to transport the sourced water throughout the pipeline network. Having access to water sources is an important element of the hydraulic fracturing process in the Delaware Basin because modern completion methods require significantly more sourced water relative to the Midland Basin.

The following table provides information regarding our gathering, compression and transportation system as of December 31, 2019:



Pipeline Infrastructure Assets
(miles)⁽¹⁾	Delaware Basin	Midland Basin	Permian Total
Crude oil	104	44	148
Natural gas	148	—	148
Produced water	257	217	474
Sourced water	26	71	97
Total	535	332	867



(capacity/capability)⁽¹⁾	Delaware Basin	Midland Basin	Permian Total	Utilization
Crude oil gathering (Bbl/d)	180,000	56,000	236,000	42	%
Natural gas compression (Mcf/d)	135,000	—	135,000	70	%
Natural gas gathering (Mcf/d)	150,000	—	150,000	56	%
Produced water gathering and disposal (Bbl/d)	1,576,500	1,732,300	3,308,800	27	%
Sourced water (Bbl/d)	120,000	455,000	575,000	83	%


(1)	Does not include any assets of the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

Throughput and Volumes

The following table provides information regarding our throughput volumes for each of the periods indicated:



	Year Ended December 31,
(throughput)⁽¹⁾	2019	2018
Crude oil gathering volumes (Bbl/d)	85,164	47,338
Natural gas gathering volumes (MMBtu/d)	85,283	39,252
Produced water gathering and disposal volumes (Bbl/d)	806,078	281,916
Sourced water gathering volumes (Bbl/d)	415,939	252,118


(1)	Does not include any volumes from the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

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Investment in long-haul crude oil pipelines

We own a 10% equity interest in EPIC Crude Holdings LP, which is building a long-haul crude oil pipeline from the Permian and the Eagle Ford Shale to Corpus Christi, Texas. Upon completion, this pipeline, which we refer to as the EPIC pipeline, will be capable of transporting approximately 590,000 Bbl/d which, with the installation of additional pumps and storage, can be increased to approximately 900,000 Bbl/d.

We also own a 10% equity interest in Gray Oak Pipeline, LLC, which is building a long-haul crude oil pipeline. Upon completion, this pipeline, which we refer to as the Gray Oak pipeline, will be capable of transporting approximately 900,000 Bbl/d from the Permian and the Eagle Ford Shale to points along the Texas Gulf Coast, including a marine terminal connection in Corpus Christi, Texas.

We also own a 4% equity interest in Wink to Webster Pipeline LLC, which is developing a long-haul crude oil pipeline. Upon completion, this pipeline, which we refer to as the Wink to Webster pipeline, will be capable of transporting over 1,000,000 Bbl/d from origin points at Wink and Midland in the Permian basin for delivery to multiple Houston area locations.

Once these pipelines are operational, our equity interests in the EPIC, Gray Oak and Wink to Webster joint ventures are expected to provide us with a steady cash flow stream from oil-weighted long-haul crude oil transportation. We anticipate that each of the EPIC and Gray Oak pipelines will commence full commercial operations in the second quarter of 2020. The Wink to Webster pipeline is expected to begin service in the first half of 2021.

Investment in gas gathering and processing system

We own a 50% equity interest in the Amarillo Rattler joint venture, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. Amarillo Rattler also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. We anticipate that the new processing plant will commence full commercial operations in the middle of 2021.

Our Relationship with Diamondback

As of December 31, 2019, 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 71% of our total units outstanding. Diamondback also owns and controls our general partner.

We believe Diamondback views our partnership as an integral part of its strategy of remaining a premier, low-cost Permian operator that can grow production at peer leading rates within cash flow. The fundamental role we play in Diamondback’s operational success allows us to capitalize on Diamondback’s expected Permian production growth 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 growth ramp in order to allow Diamondback the operational flexibility to execute on its growth plan. We believe that Diamondback will continue its strong growth trajectory as a result of its management expertise, premier asset base with a deep inventory of economic potential horizontal drilling locations, well capitalized balance sheet and operational execution track record. As such, we expect Diamondback’s production growth will drive our free cash flow growth profile. Our capital expenditure programs are tied directly to Diamondback’s activity. 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.

In addition, neither we, the Operating Company nor our general partner has any employees. Diamondback provides management, operating and administrative services to us and our general partner. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this report.

Business Strategies

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


•	Grow by leveraging our strategic relationship with Diamondback and through accretive acquisitions. We believe Diamondback, with its strong credit profile and well-capitalized balance sheet, is well positioned to pursue its growth-

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oriented upstream development strategy. We believe our provision of midstream services to Diamondback is an integral component of that strategy and critical to Diamondback’s success. Diamondback has advised us that it intends to utilize cash from distributions that it receives from us in part to fund its drilling and completion activities and drive additional production growth, which we believe will further support our growth strategy. We expect to grow organically with Diamondback as it increases production on the Dedicated Acreage, participate with Diamondback in acquisitions that contain midstream infrastructure and source additional acreage dedications from Diamondback and third-party producers and/or acquire complementary midstream assets on our own when these opportunities align with our strategic plan and are accretive to unitholders.

•

Serve as a significant provider of midstream services for Diamondback. We own and operate midstream infrastructure assets that handle a significant portion of Diamondback’s midstream gathering and water-related needs in the Midland and Delaware Basins. Our midstream assets were built or acquired to support Diamondback’s multi-year growth with minimal incremental operating capital expenditures. Diamondback has dedicated approximately 397,000 gross acres to us through the Acreage Dedications. Pursuant to this dedication, we will continue to provide water sourcing and handling for completion operations, produced water handling and disposal, crude oil transportation and gathering and natural gas gathering and compression services for Diamondback until 2034, when Diamondback has the option to extend the contract expiration date. We expect that Diamondback’s production, and therefore its need for midstream services, will grow on the Dedicated Acreage from the continued development of its core areas and we intend to utilize this relationship with Diamondback to drive free cash flow growth and the payment of distributions to our unitholders.

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Focus on cash flow generation to fund our capital plan, support our distribution policy and maximize unitholder returns. We expect that our growth will be 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, we expect to have low future operating capital expenditure requirements, which will allow us to self-fund our capital program for our core business and make distribution payments to our unitholders while limiting our reliance on the capital markets. A core component of our strategy is to maximize free cash flow while maintaining a debt to equity ratio below 2.0.

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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 15-year, 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 to successfully execute our business strategies, including:

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Fundamental, strategic relationship with Diamondback. We believe we are integral to Diamondback’s strategy and we believe the fundamental role we play in Diamondback’s operational success allows us to capitalize on Diamondback’s expected Permian production growth. We plan to build our midstream infrastructure in concert with and in advance of Diamondback’s expected production growth ramp in order to allow Diamondback the operational flexibility to execute on its growth plan. We are a significant provider of midstream services to Diamondback with Acreage Dedications that spans a total of approximately 397,000 gross acres across all of our service lines and over the core of the Midland and Delaware Basins. Our visibility into Diamondback’s drilling and production plans allows us to utilize a synchronized midstream development plan that optimizes capital spending and free cash flow generation.

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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 the general partner of Viper, and we believe their significant experience, successful track record and discipline in deploying capital at Diamondback and Viper distinguish us from our peers. We believe that the growth-oriented approach, expertise and success in the Permian of our general partner’s management team helps us deliver attractive unitholder returns.


•	Asset base located in the core of the Permian with highly visible underlying production growth. As of December 31, 2019, we have 867 miles of pipelines across the Midland and Delaware Basins with 236,000 Bbl/d of crude oil gathering capacity, 135,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering

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capacity, 3,308,800 Bbl/d of produced water gathering and disposal capacity and 575,000 Bbl/d of sourced water gathering capacity located in what we believe is the core of the Midland and Delaware Basins of the Permian and overlaying Diamondback’s seven core development areas. These areas are characterized by high return single well economics that we believe are among the best in the Lower 48 and have a deep inventory of economic horizontal drilling locations. We believe our strategically located assets provide critical midstream infrastructure for Diamondback’s multi-year organic development plan, and we expect to benefit directly from Diamondback’s execution on its operational plan and grow production. We expect to benefit disproportionately as Diamondback accelerates its development of the Delaware Basin. The core location of our assets and the close proximity to other leading E&P operators provide additional opportunities to execute third party contracts for midstream services.

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Structural and strategic alignment with unitholders. We are focused on creating differentiated unitholder value and providing strong return on and return of capital to unitholders. Through its ownership of Class B and common units in us and its ownership of membership interests in the Operating Company, Diamondback is our largest unitholder and has a 71% ownership interest in us and owns 100% of our general partner. As a result, Diamondback will directly benefit if we grow free cash flow and distributions. We do not have incentive distribution rights or subordinated units, which we believe better align 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 will increase stability and create a more liquid trading market for our common units, given our access to a potentially broader unitholder base. We believe that our relationship with Diamondback and resulting alignment of strategic and operational interests is a differentiator in the public midstream sector and provides the optimal platform to pursue a balanced plan for future growth that benefits all unitholders equally.

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High-margin business that generates significant, predictable free cash flow. Our revenue is generated as a result of our commercial agreements, which are fee-based and, as of December 31, 2019, include dedications of acreage in the Delaware Basin (approximately 187,000 gross acres) and the Midland Basin (approximately 210,000 gross acres). The fees charged under our commercial agreements are based upon the prevailing market rates at the time of execution with annual escalators (subject to potential adjustment by regulators). We believe our commercial agreements with Diamondback, which have initial terms ending in 2034, provide exposure to Diamondback’s leading growth profile with no direct commodity price exposure, thus enhancing the predictability of free cash flow and our performance. We believe the current throughput of our assets relative to Diamondback’s total capacity positions us well to increase transported volumes as Diamondback increases production pursuant to its development programs. We believe that the operational leverage from increased utilization, along with minimal incremental operating capital expenditures to meet Diamondback’s anticipated volumes, will result in significant long-term free cash flow generation that supports a self-funding model for our core business which includes the return of capital to unitholders through a distribution.

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Financial flexibility and conservative capital structure. We have a conservative capital structure that we believe will provide us with the financial flexibility to execute our business strategies. As of December 31, 2019, we had $424 million of outstanding indebtedness and $187 million of liquidity, including $176 million of available borrowings under our credit agreement. We believe that our significant liquidity and strong capital structure will allow us to execute our strategy of self-funding our currently anticipated operating capital expenditures and our distributions to our unitholders while limiting our reliance on the capital markets.

Competition

As we seek to expand our crude oil, natural gas and water-related midstream services, we face a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store or market natural gas. As we seek to expand to provide midstream services to third party producers, we similarly face a high level of competition. 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 Dedicated Acreage, we do not compete with other midstream companies to provide Diamondback with midstream services as a result of our relationship with Diamondback and long-term dedications to our midstream assets. However, Diamondback may continue to use third party service providers for certain midstream services within the Dedicated Acreage until the expiration or termination of certain pre-existing dedications.

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Seasonal Nature of Business

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

Regulation

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

Environmental Matters

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

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


•	requiring the acquisition of permits to conduct regulated activities;


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•	restricting the way we can handle or dispose of our materials or wastes;


•	limiting or prohibiting construction, expansion, modification and operational activities based on National Ambient Air Quality Standards, or NAAQS, and in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered species;


•	requiring remedial action to mitigate pollution conditions caused by our operations or attributable to former operations;


•	enjoining, or compelling changes to, the operations of facilities deemed not to be in compliance with permits issued pursuant to such environmental laws and regulations; and


•	requiring noise, lighting, visual impact, odor or dust mitigation, setbacks, landscaping, fencing and other measures; and limiting or restricting water use.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements and the issuance of orders enjoining current and future operations. Certain environmental statutes impose strict liability (i.e., no showing of “fault” is required) that may be joint and several for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for property damage or possibly personal injury allegedly caused by the release of substances or other waste products into the environment.

The historic trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. When possible, we attempt to anticipate future regulatory requirements that might be imposed and plan accordingly to manage the costs of such compliance.

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

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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. The CAA contains provisions that may result in the imposition of certain pollution control requirements with respect to air emissions from our operations. 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 addressing other air emission-related issues. 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 “– Regulation of Hydraulic Fracturing.” Also, on June 3, 2016, the EPA published a final rule regarding the criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.

Compliance with these or other new legal requirements could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations. Obtaining or renewing permits has the potential to delay the development of oil and natural gas projects.

Climate Change

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

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 greenhouse` gases. 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. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the withdrawal announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, such future laws and regulations imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations. Substantial limitations on GHG emissions could also adversely affect demand for the crude oil and natural gas we gather.

In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives

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aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Furthermore, claims have been made against certain energy companies alleging that GHG emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Moreover, there has been public discussion that 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 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 Resource Conservation and Recovery Act, 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 Resource Conservation and Recovery Act, 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 Resource Conservation and Recovery Act, 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 gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the 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, 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 gas and oil 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 Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or the Corps, jointly promulgated final rules redefining the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies published a final rule to repeal the 2015 rules. The 2015 rule and the 2019 repeal are subject to several, ongoing legal challenges. Also, on January 23, 2020, the EPA and the Corps released a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the Clean Water Act. The rule is anticipated to generate further legal challenges. Additionally, on April 23, 2019, the EPA published an interpretive statement and request for comment, clarifying that the Clean Water Act’s permitting program for discharges of pollutants does not apply to releases of pollutants to groundwater. As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the Clean Water Act.

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

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants, which regulations are discussed in more detail below under the caption “—Hydraulic Fracturing.” Costs may be associated with the treatment of wastewater or developing and 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 Clean Water Act 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 Dedicated Acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our sourced water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act.

In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The EPA is also conducting a study of private wastewater treatment facilities (also known as centralized waste treatment, or CWT, facilities) accepting oil and natural gas extraction wastewater. The EPA is collecting data and information related to the extent to which CWT facilities accept such wastewater, available treatment technologies (and their associated costs), discharge characteristics, financial characteristics of CWT facilities, and the environmental impacts of discharges from CWT facilities.

On August 16, 2012, the EPA published final regulations under the CAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on June 3, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations. Furthermore, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Legal challenges are anticipated and thus substantial uncertainty exists regarding the scope of New Source Performance standards for oil and natural gas operations. The 2012 and 2016 New Source Performance standards, to the extent implemented, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from produced water disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the U.S. Department of Energy, the U.S. Geological Survey, and the U.S. Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.

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Several states, including Texas, 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. The Texas Legislature adopted legislation, effective September 1, 2011, requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process. The Texas Railroad Commission adopted rules and regulations implementing this legislation that apply to all wells for which the Texas Railroad Commission issues an initial drilling permit after February 1, 2012. The law requires that the well operator disclose the list of chemical ingredients subject to the requirements of OSHA for disclosure on an internet website and also file the list of chemicals with the Texas Railroad Commission with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the Texas Railroad Commission. Also, in May 2013, the Texas Railroad Commission adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The rules took effect in January 2014. Additionally, on October 28, 2014, the Texas Railroad Commission adopted produced water disposal well rule amendments designed, among other things, to require applicants for new produced water disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new produced water disposal well. The produced water disposal well rule amendments, which became effective on November 17, 2014, also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a produced water disposal well permit if scientific data indicates a produced water disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for produced water disposal wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. While the EPA under the current administration has generally sought to relax environmental regulation and reduce enforcement efforts, including with respect to energy developed from unconventional sources, a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. We cannot predict the results of these or future lawsuits, or how such lawsuits will affect the regulation of hydraulic fracturing operations. Certain environmental groups have also suggested that additional laws at the federal, state and local levels of government may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. Additional levels of regulation and permits required through the adoption of new laws and regulations at the federal, state or local level could lead to delays, increased operating costs and process prohibitions that could reduce the volumes of crude oil and natural gas that move through our gathering systems and decrease demand for our water services, which in turn could materially adversely impact our revenues.

Endangered Species

The federal Endangered Species Act, or ESA, and analogous state laws restrict activities that may affect listed endangered or threatened species or their habitats. If endangered species are located in areas where we operate, our operations or any work performed related to them could be prohibited or delayed or expensive mitigation may be required. While some of our operations may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in compliance with the ESA. On August 12, 2019, the U.S. Fish and Wildlife Service and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service jointly published final rules that, among other things, tighten the critical habitat designation process and eliminate certain automatic protections for threatened species going forward. Nevertheless, the designation of previously unprotected species 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 HLPSA, and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products, including NGLs and condensate, and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. We believe that we are in compliance in all material respects with these HLPSA regulations.

We are also subject to the Natural Gas Pipeline Safety Act of 1968, or NGPSA, and the Pipeline Safety Improvement Act of 2002. The NGPSA regulates safety requirements in the design, construction, operation and maintenance of natural gas pipeline facilities while the Pipeline Safety Improvement Act establishes mandatory inspections for all United States crude oil and natural gas transportation pipelines and some gathering pipelines in high-consequence areas within ten years. DOT, through the Pipeline

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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 Hazardous Liquids Pipeline Safety Act of 1979, or HLPSA and NGPSA and increased safety regulation. The Pipeline Safety and Job Creation Act doubles the maximum administrative fines for safety violations from $100,000 to $200,000 for a single violation and from $1.0 million to $2.0 million for a related series of violations (now increased for inflation to $218,647 and $2,186,465, respectively), and provides that these maximum penalty caps do not apply to civil enforcement actions, establishes additional safety requirements for newly constructed pipelines, and requires studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines, including the expansion of integrity management, use of automatic and remote-controlled shut-off valves, leak detection systems, sufficiency of existing regulation of gathering pipelines, use of excess flow valves, verification of maximum allowable operating pressure, incident notification, and other pipeline-safety related requirements. The PIPES Act ensures that the PHMSA completes the Pipeline Safety and Job Creation Act requirements; reforms PHMSA to be a more dynamic, data-driven regulator; and closes gaps in federal standards.

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

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

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

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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 $1.2 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. Failure to comply with the NGA, EPAct 2005 and the other federal laws and regulations governing our business can result in the imposition of administrative, civil and criminal remedies.

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

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

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

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

Crude Oil Pipeline Regulation

Pipelines that transport crude oil in interstate commerce are subject to regulation by FERC pursuant to the Interstate Commerce Act, or ICA, the Energy Policy Act of 1992, and related rules and orders. The ICA requires, among other things, that tariff rates for common carrier crude oil pipelines be “just and reasonable” and not unduly discriminatory or preferential, and that

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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 1.23 percent, which is in effect until July 1, 2021. As an alternative to this indexing methodology, pipelines may also choose to support changes in their rates based on a cost-of-service methodology, by obtaining advance approval to charge “market-based rates,” or by charging “settlement rates” agreed to by all affected shippers.

We have a FERC tariff on file to gather crude oil in interstate commerce.

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

We do not have any employees. We are managed and operated by the board of directors and executive officers of our general partner. All of the employees that conduct our business, including our executive officers, are employed by Diamondback. As of December 31, 2019, Diamondback had approximately 712 fulltime employees performing services for our operations and activities.

Facilities

We own the Fasken Center which has over 421,000 net rentable square feet within its two office towers and associated assets in Midland, Texas. We, Diamondback and Viper 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

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

We derive substantially all of our revenue from our commercial agreements with Diamondback, which agreements do not contain minimum volume commitments, as well as volumes attributable to third-party interest owners that participate in Diamondback’s operated wells and are charged under short-term contracts at market sensitive rates. As a result, we are subject to the operational and business risks of Diamondback, the most significant of which include the following:


•	a reduction in or slowing of Diamondback’s drilling and development plan on the Dedicated Acreage, which would directly and adversely impact Diamondback’s demand for our midstream services;


•	the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on Diamondback’s drilling and development plan on the Dedicated Acreage or Diamondback’s ability to finance its operations and drilling and completion costs on that acreage;


•	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, associated with Diamondback’s operations on the Dedicated Acreage;


•	future wells, or wells that are currently in the process of being completed, on acreage that is dedicated to us do not produce sufficient hydrocarbons or are dry holes, which would directly and adversely impact the hydrocarbon volumes on our systems and our revenue;


•	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, we are indirectly subject to the business risks of Diamondback generally and other factors, including, among others:


•	Diamondback’s financial condition, credit ratings, leverage, market reputation, liquidity and cash flow;


•


•	Diamondback’s ability to maintain or replace its reserves;


•	adverse effects of governmental and environmental regulation on Diamondback’s upstream operations; and


•	losses from pending or future litigation.

Further, we have no control over Diamondback’s business decisions and operations, and 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, breach its commitments with respect to future dedications or otherwise fail to pay or perform, including

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with respect to our commercial agreements. We cannot predict the extent to which Diamondback’s businesses 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 plan on the Dedicated Acreage or to perform under 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. Any temporary or permanent release of volumes or acreage from the Acreage Dedications could materially adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions.

Our commercial agreements with Diamondback carry initial terms ending in 2034, and there is no guarantee that we will be able to renew or replace these agreements on equal or better terms, or at all, upon their expiration. Our ability to renew or replace our commercial agreements following their expiration at rates sufficient to maintain our current revenues and cash flow could be adversely affected by activities beyond our control, including the activities of federal and state regulators, our competitors and Diamondback.

As of December 31, 2019, 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.

We may not have sufficient cash to pay any quarterly distribution on our common units and, regardless 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 any distribution to our common unitholders; accordingly, we may not have sufficient cash each quarter to enable us to pay any distributions 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:


•	the volumes of crude oil we gather, the volumes of natural gas we gather, the volumes of produced water we collect, clean or dispose of and the volumes of sourced water we distribute and store;


•	market prices of crude oil, natural gas and NGLs and their effect on Diamondback’s drilling and development plan on the Dedicated Acreage and the volumes of hydrocarbons that are produced on the Dedicated Acreage and for which we provide midstream services;


•	Diamondback’s and our other customers’ ability to fund their drilling and development plan on the Dedicated Acreage;


•	downstream processing and transportation capacity constraints and interruptions, including the failure of Diamondback and any other customers to have sufficient contracted processing or transportation capacity;


•	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;


•	the rates we can charge for our midstream services;


•	the rates that EPIC, Gray Oak, Wink to Webster and OMOG can charge for their transportation, gathering, processing and terminal services, as applicable;


•	the terms upon which we are able to contract to provide our midstream services;


•	our existing gathering and other commercial agreements; or

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•	our operating costs or our operating flexibility;


•	the rates we charge for our midstream services;


•	the rates that EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG charge for their gathering, transportation, 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 the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG 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; 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.

Our partnership agreement does not require us to pay any distributions on our common units at all. Accordingly, 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.

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

We have ownership interests in several joint ventures, including the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG joint ventures, and we may enter into other joint venture arrangements in the future. While we own equity interests and have certain voting rights with respect to our joint ventures, we do not act as operator of or control our joint ventures, 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

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their financial obligations to the joint venture, and our joint venture partners may have economic, business or legal interests or goals that are inconsistent with ours, or those of the joint venture.

We also will likely be unable to control the amount of cash we will receive from the operation of these entities, which could further adversely affect 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.

The amount of cash we have available for distribution to our common unitholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from making distributions, even during periods in which we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record a net loss for financial accounting purposes and, conversely, we might fail to make cash distributions on our common units during periods when we record net income for financial accounting purposes.

If Diamondback sells any of the Dedicated Acreage to a third party, the third party’s financial condition could be materially worse than Diamondback’s, and thus we could be subject to the nonpayment or nonperformance by the third party.

If Diamondback sells any of the Dedicated Acreage to a third party, the third party’s financial condition could be materially worse than Diamondback’s. In such a case, we may be subject to risks of loss resulting from nonpayment or nonperformance by the third party, which risks may increase during periods of economic uncertainty. Furthermore, the third party may be subject to their own operating and regulatory risks, which could increase the risk that that third party may default on its obligations to us. Any material nonpayment or nonperformance by the third party could reduce our ability to make distributions to our common unitholders.

The Acreage Dedications are subject to additional risk in the event of a bankruptcy proceeding of Diamondback.

If in the future Diamondback is in financial distress or commences bankruptcy proceedings, our contracts with Diamondback, including the Acreage Dedication provisions, may be subject to renegotiation or rejection under applicable provisions of the United States Bankruptcy Code. If, in such a circumstance, any such contract is altered or rejected in bankruptcy proceedings, we could lose some or all of the expected revenues associated with that contract, which could have a material and adverse effect on our business, cash flow and results of operations.

Our business is difficult to evaluate because we have a limited operating history.

We were formed in July 2018 and substantially all of our assets were acquired by our Predecessor effective on or after January 1, 2016. Moreover, we do not have historical financial statements with respect to certain of our midstream assets for periods prior to their acquisition by Diamondback. As a result, there is only limited historical financial and operating information available upon which to base your evaluation of our performance.

Because of the natural decline in hydrocarbon production from existing wells, our success depends, in part, on our ability to maintain or increase hydrocarbon throughput volumes on our midstream systems, which depends on our customers’ levels of development and completion activity on our Dedicated Acreage.

The level of crude oil and natural gas volumes handled by our midstream systems depends on the level of production from crude oil and natural gas wells dedicated to our midstream systems, which may be less than expected and which will naturally decline over time. To maintain or increase throughput levels on our midstream systems, we must obtain production from wells completed by Diamondback and any third party customers on acreage dedicated to our midstream systems or execute agreements with other third parties in our areas of operation.

We have no control over Diamondback’s or other producers’ levels of development and completion activity in our areas of operation, the amount of reserves associated with wells connected to our systems or the rate at which production from a well declines. In addition, we have no control over Diamondback or other producers or their exploration and development decisions, which may be affected by, among other things:


•	the availability and cost of capital;

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•	prevailing and projected crude oil, natural gas and NGL prices;


•	demand for crude oil, natural gas and NGLs;


•	levels of reserves;


•	geologic considerations;


•	changes in the strategic importance Diamondback assigns to development in the Delaware Basin or the Midland Basin as opposed to other potential future operations they may acquire, which could adversely affect the financial and operational resources Diamondback is willing to devote to development of our Dedicated Acreage;


•	increased levels of taxation related to the exploration and production of crude oil, natural gas and NGLs in our areas of operation;


•	environmental or other governmental regulations, including the availability of permits, the regulation of hydraulic fracturing and a governmental determination that multiple facilities are to be treated as a single source for air permitting purposes; and


•	the costs of producing crude oil, natural gas and NGLs and the availability and costs of drilling rigs and other equipment.

Due to these and other factors, even if reserves are known to exist in areas served by our midstream assets, producers, including Diamondback, may choose not to develop those reserves. If producers choose not to develop their reserves or they choose to slow their development rate in our areas of operation, utilization of our midstream systems will be below anticipated levels. Reductions in development activity, coupled with the natural decline in production from our current Dedicated Acreage, would result in our inability to maintain the then-current levels of utilization of our midstream assets, which could materially adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions.

If Diamondback does not maintain its drilling activities on the Dedicated Acreage, the demand for our sourced water and produced water disposal services could be reduced, which could have a material adverse effect on our results of operations, cash flow and ability to make distributions to our common unitholders.

The sourced water and produced water disposal services we provide to Diamondback and any other customers assist in their drilling activities. If Diamondback does not maintain its drilling activities on the Dedicated Acreage, their demand for our sourced water and produced water disposal services will be reduced regardless of whether we continue to provide our other midstream services for their production. If the demand for our sourced water or produced water disposal services declines for this or any other reason, our results of operations, cash flow and ability to make distributions to our common unitholders could be materially adversely affected.

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

When acquiring oil and natural gas leases, we may not elect to incur the expense of retaining lawyers to examine the title to the mineral interest. Rather, we 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.

Our midstream assets are currently located exclusively in the Permian 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 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 or interruption of the processing or transportation of crude oil, natural gas and water. If any of these factors were to impact the Permian 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 the third-party pipelines interconnected, or expected to be interconnected, to our pipelines become unavailable to transport or store crude oil or refined products, our revenue and available cash 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, our ability to operate efficiently and continue shipping crude oil and refined products to major demand centers could be restricted, thereby reducing revenue. Any temporary or permanent interruption at these pipelines could have a material adverse effect on our business, results of operations, financial condition or cash flow, including our ability to make distributions.

We cannot predict the rate at which Diamondback will develop the Dedicated Acreage or the areas it will decide to develop.

The Acreage Dedications cover midstream services in a number of areas that are at the early stages of development, in areas that Diamondback is still determining whether to develop, and in areas where we may have to acquire operating assets from third parties. In addition, Diamondback owns acreage in areas that are not dedicated to us. We cannot predict which of these areas Diamondback will determine to develop and at what time. Diamondback may decide to explore and develop areas in which we have a smaller operating interest in the midstream assets that service that area, or where the acreage is not dedicated to us, rather than areas in which we have a larger operating interest in the midstream assets that service that area. Diamondback’s decision to develop acreage that is not dedicated to us or in which we have a smaller operating interest may adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions.

Acquisitions of assets or businesses may reduce, rather than increase, our distributable cash flow or may disrupt our business.

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our distributable cash flow. Any acquisition involves 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;


•	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.

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Diamondback may suspend, reduce or terminate its obligations under our commercial agreements with it in certain circumstances, which could have a material adverse effect on our financial condition, results of operations, cash flow and ability to make distributions to our common unitholders.

We have entered into a gas gathering and compression agreement, a crude oil gathering agreement, a produced and flowback water gathering and disposal agreement and a sourced water purchase and services agreement with Diamondback, which 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 such reduction, suspension or termination of Diamondback’s obligations under our commercial agreements would have a material adverse effect on our financial condition, results of operations, cash flow and ability to make distributions to our common unitholders.

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. In addition, competition could intensify the negative impact of factors that decrease demand for crude oil, natural gas and sourced water in the markets served by our systems, such as adverse economic conditions, weather, higher fuel costs and taxes or other governmental or regulatory actions that directly or indirectly increase the cost or limit the use of crude oil, natural gas and sourced water.

Our construction of new midstream assets 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 and legal uncertainties beyond our control, may require the expenditure of significant amounts of capital, and we may not be able to construct in certain locations due to setback requirements or expand certain facilities that are deemed to be part of a single source. Regulations clarifying how crude oil and natural gas production facility emissions must be aggregated under the CAA permitting program were finalized in June 2016. This action clarified certain permitting requirements, yet could still impact permitting and compliance costs. As we build infrastructure to meet Diamondback’s needs, we may not be able to complete such projects on schedule, at the budgeted cost or at all.

Our revenues may not increase immediately (or at all) upon the expenditure of funds on a particular project. For instance, if we build additional gathering assets, the construction may occur over an extended period of time and we may not receive any material increases in revenues until the project is completed or at all. We may construct facilities to capture anticipated future production growth from Diamondback or another customer in an area where such growth does not materialize. As a result, new midstream assets may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions.

The construction of additions to our existing assets may require us to obtain new rights-of-way, surface use agreements or other real estate agreements prior to constructing new pipelines or facilities. We may be unable to timely obtain such rights-of-way to connect new crude oil, natural gas and water sources to our existing infrastructure or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to expand or renew existing rights-of-way, leases or other agreements, and our fees may only be increased above the annual year-over-year increase by mutual

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agreement between us and our customer. If the cost of renewing or obtaining new agreements increases, our cash flow could be adversely affected.

We are subject to regulation by multiple governmental agencies, which could adversely impact our business, results of operations and financial condition.

We are subject to regulation by multiple federal, state and local governmental agencies. 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 affect our profitability.

The rates of our regulated crude oil assets are subject to review and reporting by federal regulators, which could adversely affect our revenues.

We filed a tariff to gather crude oil in interstate commerce effective September 1, 2018. Pipelines that gather or transport crude oil for third parties in interstate commerce are, among other things, subject to rate regulation by FERC. We may also be required to respond to requests for information from government agencies, including compliance audits conducted by FERC.

FERC’s ratemaking policies are subject to change and may impact the rates charged and revenues received by us. In July 2016, the United States Court of Appeals for the District of Columbia Circuit issued its opinion in United Airlines, Inc., et al. v. FERC, finding that FERC had acted arbitrarily and capriciously when it failed to demonstrate that permitting an interstate petroleum products pipeline organized as a master limited partnership, or MLP, to include an income tax allowance in the cost of service underlying its rates in addition to the discounted cash flow return on equity would not result in the pipeline partnership owners double-recovering their income taxes. The court vacated FERC’s order and remanded to FERC to consider mechanisms for demonstrating that there is no double recovery as a result of the income tax allowance. On March 15, 2018, FERC issued a Revised Policy Statement on Treatment of Income Taxes in which FERC found that an impermissible double recovery results from granting a MLP pipeline both an income tax allowance and a return on equity pursuant to FERC’s discounted cash flow methodology. FERC revised its previous policy, stating that it would no longer permit an MLP pipeline to recover an income tax allowance in its cost of service. FERC stated it will address the application of the United Airlines decision to non-MLP partnership forms as those issues arise in subsequent proceedings. Further, FERC stated that it will incorporate the effects of the post-United Airlines policy changes and the Tax Cuts and Jobs Act of 2017 on industry-wide crude oil pipeline costs in the 2020 five-year review of the crude oil pipeline index level. FERC will also apply the revised Policy Statement and the Tax Cuts and Jobs Act of 2017 to initial crude oil pipeline cost-of-service rates and cost-of-service rate changes on a going-forward basis under FERC’s existing ratemaking policies, including cost-of-service rate proceedings resulting from shipper-initiated complaints. On July 18, 2018, FERC dismissed requests for rehearing and clarification of the March 15, 2018 Revised Policy Statement, but provided further guidance, clarifying that a pass-through entity will not be precluded in a future proceeding from arguing and providing evidentiary support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double recovery of investors’ income tax costs.

A change in the jurisdictional characterization of some of our assets by federal, state or local regulatory agencies or a change in policy by those agencies 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.

Although FERC has not made a formal determination with respect to the facilities we consider to be natural gas gathering pipelines, we believe that our natural gas gathering pipelines meet the traditional tests that FERC has used to determine that pipelines perform primarily a gathering function and are, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated interstate transportation services and federally unregulated gathering services, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA, and that the facility provides interstate transportation service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act, or NGPA. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flow. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

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Even though we consider our natural gas gathering pipelines to be exempt from the jurisdiction of FERC under the NGA, FERC regulation of interstate natural gas transportation pipelines may indirectly impact gathering services. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets and gathering services. In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that the FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. Our gathering operations could also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities. 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 operating costs depending on future legislative and regulatory changes.

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.

The U.S. Department of Transportation, or DOT, through the PHMSA and state agencies, enforces safety regulations with respect to the design, construction, operation, maintenance, inspection and management of certain of our pipeline facilities. The PHMSA requires pipeline operators to implement integrity management programs, including more frequent inspections and other measures to ensure pipeline safety in high-consequence areas, or HCAs, defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. The regulations require operators to (i) perform ongoing assessments of pipeline integrity, (ii) identify and characterize applicable threats to pipeline segments that could impact a HCA, (iii) improve data collection, integration and analysis, (iv) repair and remediate pipelines as necessary and (v) implement preventive and mitigating actions. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. The PHMSA’s regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans, including extensive spill response training for pipeline personnel.

The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, also known as the Pipeline Safety and Job Creation Act, and the PIPES Act, are the most recent enactments of federal legislation to amend the NGPSA and the HLPSA which are pipeline safety laws requiring increased safety measures for natural gas and hazardous liquids pipelines. Among other things, the Pipeline Safety and Job Creation Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, material strength testing and verification of the maximum allowable pressure of certain pipelines. The Pipeline Safety and Job Creation Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and from $1.0 million to $2.0 million for a related series of violations. Effective July 31, 2019, to account for inflation, those maximum civil penalties were increased to $218,647 per violation per day, with a maximum of $2,186,465 for a related series of violations. 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.

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 gathering lines. The safety enhancement requirements and other provisions of the Pipeline Safety and Job Creation Act and the PIPES Act, as well as any implementation of PHMSA rules thereunder and/or related rule making proceedings, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

If third party pipelines or other facilities 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.

Our midstream systems are connected to other pipelines or facilities, the majority of which are owned by third parties. The continuing operation of such third party pipelines or facilities is not within our control. If any of these pipelines or facilities becomes unable to transport, treat or process natural gas or crude oil, or if the volumes we gather or transport do not meet the

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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.

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.

Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil and natural gas production by our customers, which could reduce the throughput on our gathering and other midstream systems, which could adversely impact our revenues.

We do not conduct hydraulic fracturing operations, but substantially all of Diamondback’s crude oil and natural gas production on our Dedicated Acreage is developed from unconventional sources that require hydraulic fracturing as part of the completion process. The majority of our sourced water services business is related to the storage and transportation of water for use in hydraulic fracturing. Hydraulic fracturing is a well stimulation process that utilizes large volumes of water and sand combined with fracturing chemical additives that are pumped at high pressure to crack open previously impenetrable rock to release hydrocarbons. There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally.

Hydraulic fracturing is typically regulated by state oil and gas commissions and similar agencies. Some states and local governments, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure or well construction requirements on hydraulic fracturing operations. In addition, several states and local governments have banned or significantly restricted hydraulic fracturing and, over the past several years, federal agencies such as the EPA have sought to assert jurisdiction over the process. While the EPA under the current administration has generally sought to relax environmental regulation and reduce enforcement efforts, including with respect to energy developed from unconventional sources, environmental groups and states have filed lawsuits challenging the EPA’s recent actions. We cannot predict the results of these or future lawsuits, or how such lawsuits will affect the regulation of hydraulic fracturing operations. Certain environmental groups have also suggested that additional laws at the federal, state and local levels of government may be needed to more closely and uniformly regulate the hydraulic fracturing process. We cannot predict whether any such legislation will be enacted and if so, what its provisions would be. 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, Diamondback or any third party customers may incur significant liability under, or costs and expenditures to comply with, environmental and worker health and safety regulations, which are complex and subject to frequent change.

As an owner and operator of gathering systems, we are subject to various federal, state and local laws and regulations relating to the discharge of materials into, and protection of, the environment and worker health and safety. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring costly response actions. These laws and regulations may impose numerous obligations that are applicable to our and our customers’ operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our or our customers’ operations, the imposition of specific standards addressing worker protection and the imposition of substantial liabilities and remedial obligations for pollution or contamination resulting from our and our customers’ operations. These laws and regulations may also limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas, and other protected areas. Failure to comply with these laws, regulations and permits may result in strict liability (i.e., no showing of “fault” is required) that may be joint and several, or the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations or the issuance of injunctions or administrative orders limiting or preventing some or all of our operations. Private parties, including the owners of the properties through which our gathering

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systems pass, may also have the right to pursue legal actions to enforce compliance, as well as to seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. We may not be able to recover all or any of these costs from insurance. In addition, we may experience a delay in obtaining or be unable to obtain required permits, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenues, which in turn could affect the amount of cash we have available for distribution. We cannot provide any assurance that changes in or additions to public policy regarding the protection of the environment and worker health and safety will not have a significant impact on our operations and the amount of cash we have available for distribution.

Our operations also pose risks of environmental liability due to leakage, migration, releases or spills to surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Moreover, public interest in the protection of the environment has increased in recent years. Even if federal regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations applied to the crude oil and natural gas industry may continue in the long-term, and at the state and local levels, potentially resulting in increased costs of doing business and consequently affecting the amount of cash we have available for distribution.

Climate change laws and regulations restricting emissions of greenhouse gases could result in increased operating costs and reduced demand for the crude oil and natural gas that we gather while potential physical effects of climate change could disrupt Diamondback’s and our other customers’ production and cause us to incur significant costs in preparing for or responding to those effects.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, present an endangerment to public health and the environment, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions 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, on June 3, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, in a March 28, 2017 executive order, President Trump directed the EPA to review the 2016 regulations and, if appropriate, to initiate a rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. On June 16, 2017, the EPA published a proposed rule to stay for two years certain requirements of the 2016 regulations, including fugitive emission requirements. Also, on October 15, 2018, the EPA published a proposed rule to significantly reduce regulatory burdens imposed by the 2016 regulations. Furthermore, on August 28, 2019, the EPA proposed amendments to the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. Legal challenges are anticipated and thus substantial uncertainty exists regarding the scope of New Source Performance standards for oil and natural gas operations. The 2012 and 2016 standards, to the extent implemented. The 2012 and 2016 standards, to the extent implemented, as well as future laws and their implementing regulations, could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

Climate and related energy policy, laws and regulations could change quickly, and substantial uncertainty exists about the nature of many potential developments that could impact the sources and uses of energy. 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. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the United States. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. On November 4, 2019, the Trump Administration submitted its formal notification of withdrawal to the United Nations. It is not clear what steps, if any, will be taken to negotiate a new agreement, or what terms would be included in such an agreement. In response to the withdrawal announcement,

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many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord. It is not possible at this time to predict the timing or effect of international treaties or regulations on our operations or to predict with certainty the future costs that we may incur in order to comply with such treaties or regulations.

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, any 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, natural gas and water we gather. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in crude oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for energy infrastructure projects, such as pipelines and terminal facilities. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our operations or our customer’s exploration and production operations, which in turn could affect demand for our services.

Legislation or 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.

We dispose of large volumes of produced water gathered from Diamondback and our other customers produced in connection with their drilling and production operations by injecting it into wells pursuant to permits issued to us by governmental authorities overseeing such disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. For example, there exists a growing concern that the injection of produced water into belowground disposal wells triggers seismic activity in certain areas, including Texas, where we operate.

State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity. In addition, a number of lawsuits have been filed in some states, most recently in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. For example, on October 28, 2014, the Texas Railroad Commission adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water or other oil and gas waste to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. If the permittee or an applicant of a disposal well permit fails to demonstrate that the produced water or other fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Texas Railroad Commission has used this authority to deny permits for disposal wells.

The adoption and implementation of any new laws or regulations that restrict our ability to dispose of produced water gathered from Diamondback and our other third party crude oil and natural gas producing customers, by limiting volumes, disposal rates, produced water disposal well locations or otherwise, or requiring us to shut down our produced water disposal wells, could have a material adverse effect on our business, financial condition and results of operations.

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.

The ESA, restricts activities that may affect endangered or threatened species or their habitats. Many states have analogous laws designed to protect endangered or threatened species. Such protections, and the designation of previously undesignated species under such laws, may affect our and Diamondback’s operations, and those of our other customers, by imposing additional costs, approvals and accompanying delays.

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

Our operations are subject to all of the hazards inherent in the gathering of crude oil, natural gas and produced water and the delivery and storage of sourced water, including:


•	damage to pipelines, centralized gathering facilities, pump stations, related equipment and surrounding properties caused by design, installation, construction materials or operational flaws, natural disasters, acts of terrorism or acts of third parties;


•	leaks of crude oil, natural gas or NGLs or losses of crude oil, natural gas or NGLs as a result of the malfunction of, or other disruptions associated with, equipment or facilities;


•	fires, ruptures and explosions; and


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

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:


•	injury or loss of life;


•	damage to and destruction of property, natural resources and equipment;


•	pollution and other environmental damage;


•	regulatory investigations and penalties;


•	suspension of our operations; and


•	repair and remediation costs.

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

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

We may not own in fee the land on which our midstream systems have been constructed. We own in fee less than 5% of the land on which our midstream systems have been constructed, with the remainder held by surface use agreements, rights-of-way, surface leases or other easement rights, which may limit or restrict our rights or access to or use of the surface estates. Accommodating these competing rights of the surface owners may adversely affect our operations. In addition, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, surface leases or other easement rights or if such usage rights lapse or terminate. We may obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these 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.

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

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

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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 nor our general partner have 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 nor our general partner have any employees and we rely solely on Diamondback to operate our assets and perform other management, administrative and operating services for us and our general partner.

Diamondback provides similar activities with respect to its own assets and operations, as well as the assets and operations of Viper. Because Diamondback provides services to us that are similar to those performed for itself and its affiliates, Diamondback may not have sufficient human, technical and other resources to provide those services at a level that Diamondback would be able to provide to us if it were solely focused on our business and operations and those of its affiliates. Diamondback may make internal decisions on how to allocate its available resources and expertise that may not always be in our best interest compared to Diamondback’s interests. There is no requirement that Diamondback favor us over itself or others in providing its services. If the employees of Diamondback and their affiliates do not devote sufficient attention to the management and operation of our business, our financial results may suffer and our ability to make distributions to our common unitholders may be reduced.

Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations and ability to make quarterly cash distributions to our common unitholders.

We entered into a revolving credit facility at the closing of our IPO. The revolving credit facility limits our 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;


•	enter into certain types of transactions with affiliates;


•	merge or consolidate with another company; and


•	transfer, sell or otherwise dispose of assets.

Our revolving credit facility also contains covenants requiring us to maintain certain financial ratios.

The provisions of our revolving credit facility may affect our ability to obtain future financing and to pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our common unitholders could experience a partial or total loss of their investment.

Our level of indebtedness could limit our flexibility to obtain financing and to pursue other business opportunities.

As of December 31, 2019, we had total long-term debt of $424.0 million consisting of outstanding borrowings under the Operating Company’s revolving credit facility. As of December 31, 2019, the borrowing base under the Operating Company’s revolving credit facility was $600.0 million. We and the Operating Company may in the future incur significant additional

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indebtedness under our revolving credit facilities or otherwise in order to fund our operations, fund capital contributions related to our joint ventures or for other purposes.

Our level of debt could have important consequences to us, including the following:


•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures (including building additional gathering pipelines needed for required connections and building additional centralized gathering facilities pursuant to our gathering agreements) or other purposes may be impaired or such financing may not be available on favorable terms;


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


•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and


•	our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will be forced to take actions such as reducing distributions, reducing or delaying our business activities, investments or capital expenditures, selling assets or issuing equity. We may not be able to effect any of these actions on satisfactory terms or at all.

Increases in interest rates could adversely affect our business.

We have exposure to increases in interest rates. At the closing of our IPO, the Operating Company entered into a revolving credit facility. An increase in the interest rates we pay under the credit facility will result in an increase in our interest expense. As a result, 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.

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. The applicable margin ranges from 0.250% to 1.250% per annum 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). LIBOR tends to fluctuate based on multiple facts, including general short-term interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. We have not hedged our interest rate exposure with respect to our floating rate debt. Accordingly, our interest expense for any particular period will fluctuate based on LIBOR and other variable interest. As of December 31, 2019, there was $424.0 million in borrowings outstanding under the revolving credit facility, with a weighted average interest rate of 2.98%. If interest rates increase, so will our interest costs, which may have a material adverse effect on our results of operations and financial condition.

On July 27, 2017, the U.K. Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United States or elsewhere.

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 $11.3 million on our balance sheet related to our future closure obligations of our produced water facilities and oil and gas gathering systems as of December 31, 2019. 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

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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 unitholders.

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

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

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

Terrorist activities, cyber-attacks, anti-terrorist efforts, other armed conflicts involving the United States or other countries or global or national health concerns, including the outbreak of pandemic or contagious disease such as the coronavirus, may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur, the resulting political instability and societal disruption could reduce overall demand for crude oil and natural gas, potentially putting downward pressure on demand for our services and causing a 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. For example, software programs are used to manage gathering and transportation systems and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as crude oil and natural gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data and to communicate with our employees and business service providers. Our business service providers, including vendors and financial institutions, are also dependent on digital technology. 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-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

Our technologies, systems, networks and those of our business partners may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

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 in the following ways, among others:


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


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


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

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


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

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 own a 60% interest in the OMOG joint venture, which is operated by Oryx. While we have the ability to influence certain business decisions affecting the OMOG joint venture, the success of our investment in the OMOG joint venture will depend on Oryx’s operation of the OMOG joint venture.

While we own a 60% interest in the OMOG joint venture, Oryx is the operator of the joint venture, and accordingly, we depend on Oryx for the day-to-day operations of the OMOG joint venture. Our lack of control over the OMOG joint venture’s day-to-day operations and the associated costs of operations could result in receiving lower cash distributions from the Joint Venture than currently anticipated, which could reduce our cash available for distribution to our unitholders. In addition, differences in views among the owners of the Joint Venture could result in delayed decisions or in failures to agree on significant matters, potentially adversely affecting the business and results of operations or prospects of the Joint Venture and, in turn, the amount of cash from the OMOG joint venture operations distributed to us.

We conduct a portion of our operations through joint ventures, which subjects us to risks that could have a material adverse effect on the accuracy of our reported financial position, results of operations, or cash flows.

We have ownership interests in several joint ventures, and we may enter into other joint venture arrangements in the future. The nature of our joint ventures grant operatorship, which includes the accounting for operations of the joint venture, to our joint venture partners. These joint ventures have controls environments independent of our oversight and review. Contractually, we can only exercise limited review and perform limited queries into the accounting performed by the operators. We have no control over the actual day-to-day accounting performed by the operator. 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. These inaccuracies may result in material misstatements in our reported consolidated financial results. If an operator determines that material misstatements have occurred in a joint venture’s previously issued financials, it may result in a material misstatement for us that can result in the need to restate and reissue previously issued consolidated financials as filed with the SEC.

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 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

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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;


•	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, limits our general partner’s liabilities and restricts the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;


•	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 unitholders;


•	our general partner determines which costs incurred by it and its affiliates are reimbursable by us;


•	our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with its affiliates on our behalf;


•	our general partner intends to limit its liability regarding our contractual and other obligations;


•	our general partner may exercise its right to call and purchase common units if it and its affiliates own more than 97% of the common units and Class B units, taken together (which threshold will be permanently reduced to 80% if our general partner and its affiliates (including Diamondback) collectively own less than 75% of the common units and Class B units, taken together);


•	our general partner controls the enforcement of obligations that it and its affiliates owe to us; and


•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

In addition, Diamondback or its affiliates may compete with us.

Our partnership agreement replaces our general partner’s fiduciary duties to our unitholders.

Our partnership agreement contains provisions that eliminate and replace the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:


•	how to allocate business opportunities among us and its affiliates;


•	whether to exercise its call right;


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


•	whether to exercise its registration rights; and


•	whether or not to consent to any merger or consolidation of us or any amendment to our partnership agreement.

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By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is generally required to make such determination, or take or decline to take such other action, in good faith, and will not be subject to any higher standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•

our general partner and its executive officers and directors will not be liable for monetary damages or otherwise to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that such losses or liabilities were the result of conduct in which our general partner or its executive officers or directors engaged in bad faith, willful misconduct or fraud or, with respect to any criminal conduct, with knowledge that such conduct was unlawful; and


•	our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our limited partners if a transaction, even a transaction with an affiliate or the resolution of a conflict of interest, is:


•	approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or


•	approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, other than one where our general partner is permitted to act in its sole discretion, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Diamondback and other affiliates of our general partner may compete with us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than acting as our general partner, engaging in activities incidental to its ownership interest in us and providing management, advisory and administrative services to its affiliates or to other persons. However, affiliates of our general partner, including Diamondback, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. In addition, Diamondback may compete with us for investment opportunities and may own an interest in entities that compete with us. Further, Diamondback and its affiliates, may acquire, develop or dispose of additional midstream properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets.

Diamondback is an established participant in the oil and natural gas industry and has resources greater than ours, which factors may make it more difficult for us to compete with Diamondback with respect to commercial activities as well as for potential acquisitions. As a result, competition from Diamondback and its affiliates could adversely impact our results of operations and cash available for distribution to our common unitholders.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Diamondback. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us does not have any duty to communicate or offer such opportunity to us. Any such person or entity is not liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires

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such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units trade.

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.

Our general partner may not be removed except by a vote of the holders of at least 66 2/3% of the outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. 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, 2019, Diamondback owned 107,815,152 of our Class B units representing 71% of voting interests in us. This gives Diamondback the ability to prevent the removal of our general partner.

Furthermore, common unitholders’ voting rights are further restricted by our partnership agreement provision providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of our management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

If our common unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. Common unitholders are unable to remove our general partner without its consent because affiliates of our general partner own sufficient units to be able to prevent its removal. The vote of the holders of at least 66 2/3% of all outstanding units, voting as a single class, is required to remove our general partner. As of December 31, 2019, Diamondback owned 107,815,152 of our Class B units representing 71% of voting interests in us.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by 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, may not 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 ability of our common unitholders to influence the manner or direction of management.

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.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations, all of which expenses are paid by us. Except to the extent reimbursed pursuant to our services and secondment agreement, our general partner determines the amount of these expenses. Under our services and secondment agreement, we are required to reimburse Diamondback for the

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provision of certain operation services and related management services in support of our operations. Our general partner and its affiliates also may provide us other services for which we are charged fees as determined by our general partner. The costs and expenses for which we reimburse our general partner and its affiliates may 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. The costs and expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. Payments to our general partner and its affiliates may be substantial and will reduce the amount of cash we have available to distribute to common unitholders.

At the closing of our IPO, we entered into a tax sharing agreement with Diamondback, or the tax sharing agreement, pursuant to which we are required to reimburse Diamondback for our share of state and local income and other taxes borne by Diamondback as a result of our results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on the closing date of our IPO. For the year ended December 31, 2019, we accrued $0.2 million for Texas margin tax payable pursuant to the tax sharing agreement with Diamondback.

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

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

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

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, or the Delaware Act, we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of any impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to us are not counted for purposes of determining whether a distribution is permitted.

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

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 allows our general partner to determine, in good faith, any amounts to pay itself or its affiliates for any services rendered to us. Our general partner may also enter into additional contractual arrangements with any of its affiliates on our behalf. Our general partner determines in good faith the terms of any arrangement or transaction entered into. Similarly, agreements, contracts or arrangements between us and our general partner and its affiliates will not be required to be negotiated on an arm’s-length basis, although, in some circumstances, our general partner may determine that the conflicts committee may make a determination on our behalf with respect to such arrangements.

Our general partner and its affiliates have no obligation to permit us to use any assets or services of our general partner and its affiliates, except as may be provided in contracts entered into specifically for such use. There is no obligation of our general partner and its affiliates to enter into any contracts of this kind.

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Common unitholders have no right to enforce the obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other hand, do not grant to the common unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

Our general partner has a call right that may require unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates (including Diamondback) own more than 97% of our then-outstanding common units and Class B units, taken together, 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 the common units over the 20 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. (If, however, our general partner and its affiliates (including Diamondback) reduce their collective ownership of common units and Class B units to below 75% of the outstanding units, taken as a whole, the ownership threshold to exercise the call right will be permanently reduced to 80%.) 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 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. The common units and Class B units are considered limited partner interests of a single class for these provisions. As of December 31, 2019, our general partner, Diamondback and its affiliates owned no common units and Diamondback beneficially owned all of our 107,815,152 outstanding Class B units.

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.

There are no limitations in our partnership agreement on our ability to issue units ranking senior to the common units.

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

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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.

As of December 31, 2019, Diamondback held 107,815,152 Class B units, each of which, together with one of our common units, are exchangeable for one common unit. All of the Class B units are beneficially owned by Diamondback and Class B units must be redeemed (together with an equal number of OpCo units) for common units prior to their sale to any person or entity not affiliated with Diamondback. Sales by holders of a substantial number of our common units in the public markets, or the perception that such sales might occur, could have a material adverse effect on the price of our common units or could impair our ability to obtain capital through an offering of equity securities. In addition, we have provided certain registration rights to Diamondback. Pursuant to these registration rights, we have agreed to register, under the Securities Act, all of the common units owned by Diamondback and its assignees for resale (including common units issuable in exchange for Class B units and our OpCo units). Under our partnership agreement, our general partner and its affiliates also have registration rights relating to the offer and sale of any common units that they hold.

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

We are classified as an “emerging growth company” under Section 2(a)(19) of the Securities Act. For as long as we are an emerging growth company, which may be up to five full fiscal years, unlike other public companies, we are not required to, among other things, (i) provide an auditor’s attestation report on management’s assessment of the effectiveness of our system of internal control over financial reporting pursuant to Section 404(b) of the Sarbanes-Oxley Act of 2002, (ii) comply with any new requirements adopted by the Public Company Accounting Oversight Board requiring mandatory audit firm 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.

Diamondback is a publicly traded corporation and has developed a system of internal controls for compliance with public reporting requirements. However, prior to our IPO, our Predecessor had not been required to file reports with the SEC on a stand-alone basis. Upon the completion of our IPO, we became subject to the public reporting requirements of the Exchange Act. 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. 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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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. If a dispute were to arise between a limited partner and us or our officers, directors or employees, the limited partner may be required to pursue its legal remedies in Delaware which may be an inconvenient or distant location and which is considered to be a more corporate-friendly environment. These provisions may have the effect of discouraging lawsuits against us and our general partner’s directors and officers.

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.

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

We are a Delaware limited partnership and, on May 24, 2019, we elected to be treated as a corporation for U.S. federal income tax purposes. As a result, we are subject to tax as a corporation at the corporate tax rate of 21%. While we expect to generate net operating losses to offset taxable income through 2020, 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 will likely 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.

Recently enacted U.S. tax legislation as well as future U.S. tax legislations may adversely affect our business, results of operations, financial condition and cash flow.

On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as the Tax Cuts and Jobs Act, which we refer to as the Tax Act, that significantly reforms the Internal Revenue Code of 1986, as amended, which we refer to as the Code. Among other changes, the Tax Act (i) reduces the maximum U.S. corporate income tax rate from 35% to 21%, (ii) preserves long-standing upstream oil and gas tax provisions such as immediate deduction of intangible drilling, (iii) allows for immediate expensing of capital expenditures for tangible personal property for a period of

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time, (iv) modifies the provisions related to the limitations on deductions for executive compensation of publicly traded corporations and (v) enacts new limitations regarding the deductibility of interest expense. The Tax Act is complex and far-reaching, and while we have evaluated the resulting impact of its enactment on us and recorded adjustments as required in our financial statements, aspects of the Tax Act are unclear and may not be clarified for some time. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued, and any such changes in our interpretations and assumptions could have an adverse effect on our business, results of operations, financial condition and cash flow.

In addition, 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 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. While these specific changes are not included in the Tax Act, 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, results of operations, financial condition and cash flows.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

Due to the nature of our business, we may be, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. See “Item 8. Financial Statements and Supplementary Data – Note 17. Commitments and Contingencies.”

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

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PART II

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

Market Information and Cash Distributions to Unitholders

Our common units are listed on the Nasdaq Global Select Market under the symbol “RTLR”. Our common units began trading on May 23, 2019 at an initial public offering price of $17.50 per common unit. The following table sets forth the range of high and low sales prices per common unit, as reported by the Nasdaq Stock Market LLC, for the periods presented:



	High		Low		Cash Distributions per Common Unit⁽¹⁾
2019
2nd Quarter (beginning May 23, 2019)	$	20.00	$	17.49	$	—
3rd Quarter	$	20.24	$	16.25	$	0.34
4th Quarter⁽²⁾	$	18.41	$	14.01	$	0.29


⁽¹⁾	Distributions are shown for the quarter in which they were generated; provided, however, the Q3 2019 distribution also includes amounts attributable to Q2 2019 commencing upon the closing of our IPO.


⁽²⁾	The Q4 2019 distribution is payable on March 10, 2020 to unitholders of record at the close of business on March 3, 2020.

Holders of Record

There was 1 holder of record of our common units on February 14, 2020.

Cash Distribution Policy

At the closing of the IPO, the board of directors of our general partner adopted a policy for us to distribute cash distributions to common unitholders of record on the applicable record date of $0.25 per common unit for each quarter beginning with the quarter ending September 30, 2019. Our first distribution of $0.34, included available cash for the period from May 28, 2019, the date of the close of our IPO, through September 30, 2019. On February 13, 2020, the board of directors of our general partner revised our cash distribution policy to provide that cash distributions will be made to common unitholders of record on the applicable record date of $0.29 per common unit for each quarter ending after December 31, 2019.

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.

Our Class B units are entitled to quarterly aggregate cash preferred distributions of 8% per annum on the $1.0 million capital contribution made in respect of such units, or $0.02 million in aggregate per quarter to all Class B units, and our general partner is entitled to a quarterly cash preferred distribution of 8% per annum on the $1.0 million capital contribution made in respect of its general partner interest, or $0.02 million per quarter. We are required to make these distributions in any quarter before making any distributions on our common units. Other than those amounts, neither our general partner interest nor our Class B units are entitled to receive or participate in distributions made by us.

Our general partner owns a non-economic general partner interest and therefore is not entitled to receive cash distributions, except that it is entitled to a quarterly cash preferred distribution of 8% per annum on the $1.0 million capital contribution made in respect of its general partner interest. However, it may acquire common units and other equity interests in the future and will be entitled to received pro rata distributions in respect of those equity interests.

Recent Sales of Unregistered Securities

None.

Repurchases of Equity Securities

None.

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ITEM 6. SELECTED FINANCIAL DATA

This section presents our selected historical consolidated financial data. The selected historical consolidated financial data presented below is not intended to replace our historical consolidated financial statements. The following selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes, each of which is included elsewhere in this Annual Report.

Rattler Midstream LP was formed in July 2018 and did not own any assets prior to May 28, 2019, the date of the equity contribution agreement by and between the Partnership and the Predecessor. Prior to the IPO, the Predecessor was a wholly owned subsidiary of Diamondback. For periods prior to May 28, 2019, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in members’ equity of the Predecessor and, for periods on and after May 28, 2019, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in unitholders’ equity of the Partnership and its partially owned subsidiary.

The following table presents selected historical financial data for the periods and as of the dates indicated. The selected historical financial data for the years ended December 31, 2019, 2018 and 2017 and the balance sheet data as of December 31, 2019 and 2018 are derived from the audited consolidated financial statements appearing elsewhere in this Annual Report. The historical financial data for the year ended 2016 and the balance sheet data as of December 31, 2017 and 2016 are derived from our previously filed audited financial statements, which are included in our final prospectus dated May 22, 2019 and filed with the SEC on May 24, 2019 pursuant to Rule 424(b) under the Securities Act.



	Year Ended December 31,
	2019	2018	2017	2016
	(In thousands, except per unit data)
Statement of Operations Data:
Total revenues	$447,673	$184,467	$39,295	$10,607
Total costs and expenses	228,333	104,148	15,308	3,595
Income from operations	219,340	80,319	23,987	7,012
Total other income (expense), net	(7,368)	—	1,366	676
Net income before income taxes	211,972	80,319	25,353	7,688
Provision for income taxes	26,253	17,359	4,688	2,760
Net income after taxes	$185,719	$62,960	$20,665	$4,928
Net income attributable to non-controlling interest subsequent to IPO	90,922
Net income attributable to Rattler Midstream LP	$28,802

Allocation of net income:
Net income before IPO	$65,995
Net income subsequent to IPO	119,724
Total net income	$185,719

Net income attributable to limited partners per common unit - subsequent to IPO:
Basic	$0.64
Diluted	$0.64

Weighted average number of limited partner common units outstanding:
Basic	43,622
Diluted	43,622

Cash distributions declared per common unit	$0.63

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	As of December 31,
(In thousands)	2019		2018		2017		2016
Balance Sheet Data:
Cash	$	10,633	$	8,564	$	8	$	—
Total property, plant and equipment, net	958,145		457,944		255,323		81,448
Total real estate assets including intangible lease assets, net	106,749		103,977		—		—
Total assets	1,636,393		604,017		299,605		95,683
Long-term debt	424,000		—		—		—
Total liabilities	520,553		76,891		6,997		2,954
Total unitholders’ equity	739,537		527,126		292,608		92,729
Total equity	$	1,115,840	$	527,126	$	292,608	$	92,729



	Year Ended December 31,
(In thousands)	2019			2018			2017		2016
Other Financial Data:
Net cash provided by operating activities	$	218,193		$	173,431		$	8	$	—
Net cash used in investing activities	(578,369		)	(164,876		)	—		—
Net cash provided by financing activities	362,245			1			—		—



	Year Ended December 31,
(In thousands)	2019		2018		2017		2016
Adjusted EBITDA⁽¹⁾	$	264,724	$	105,453	$	28,839	$	8,561


(1)	For more information, please read “–Non-GAAP Financial Measure” below.

Non-GAAP Financial Measure

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

We define Adjusted EBITDA as net income before income taxes, interest expense, net of amount capitalized, interest expense related to equity method investments, non-cash unit-based compensation expense, depreciation, amortization and accretion and other non-cash transactions. Depreciation, amortization and accretion includes depreciation, amortization and accretion on assets and liabilities of the Operating Company, in addition to our proportional interest of depreciation, amortization and accretion on our equity method investments. Interest expense related to equity method investments represents our proportional interest income (expense) from equity method investments. The GAAP measure most directly comparable to Adjusted EBITDA is net income. Adjusted EBITDA should not be considered an alternative to net income or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA excludes some, but not all, items that affect net income, and these measures may vary from those of other companies. As a result, Adjusted EBITDA as presented below may not be comparable to similarly titled measures of other companies.

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The following table presents a reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measures for each of the periods indicated:



	Year Ended December 31,
	2019			2018		2017		2016
	(In thousands)
Reconciliation of Net Income to Adjusted EBITDA:
Net income	$	185,719		$	62,960	$	20,665	$	4,928
Depreciation, amortization and accretion	42,336			25,134		3,486		873
Interest expense, net of amount capitalized	1,039			—		—		—
Interest expense related to equity method investments	1,005			—		—		—
Depreciation related to equity method investments	1,636			—		—		—
Non-cash unit-based compensation expense	5,208			—		—		—
Other non-cash transactions	1,528			—		—		—
Provision for income taxes	26,253			17,359		4,688		2,760
Adjusted EBITDA	264,724			$	105,453	$	28,839	$	8,561
Less: Adjusted EBITDA prior to the IPO	(100,743		)
Adjusted EBITDA subsequent to the IPO	163,981
Less: Adjusted EBITDA attributable to non-controlling interest	(116,685		)
Adjusted EBITDA attributable to Rattler Midstream LP	$	47,296

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ITEM 7.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Our Predecessor financial statements include 100% of the operations of the Operating Company, reflecting the historical ownership of these assets by Diamondback. This Annual Report includes the assets, liabilities and results of operations of our Predecessor for periods prior to May 28, 2019, the date on which we completed the IPO. Our future results of operations may not be comparable to our Predecessor’s historical results of operations.

Unless the context otherwise requires, references in this section to “we,” “our,” “us” or like terms, when used in a historical context prior to the completion of our IPO, refer to our Predecessor and, when used in a historical context following the completion of our IPO, the present tense or future tense, these terms refer to the Partnership and its subsidiaries.

Overview

We are a growth-oriented Delaware limited partnership formed by Diamondback in July 2018 to own, operate, develop and acquire midstream 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.

We provide crude oil, natural gas and water-related midstream services (including water sourcing and transportation and produced water gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of December 31, 2019, our midstream infrastructure assets include 867 miles of pipeline across the Midland and Delaware Basins with approximately 236,000 Bbl/d of crude oil gathering capacity, 135,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering capacity, 3.3 MMBbl/d of produced water disposal capacity and 575,000 Bbl/d of sourced water gathering capacity. In addition to our midstream infrastructure assets, we own equity interests in three long-haul crude oil pipelines, which, upon completion, will run from the Permian to the Texas Gulf Coast. In addition, we own equity interests in third-party operated gathering systems and processing facilities supported by dedications from Diamondback. We are critical to Diamondback’s growth plans because we provide a long-term midstream solution to its increasing crude oil, natural gas and water-related services needs through our robust infield gathering systems and produced water disposal capabilities.

As of December 31, 2019, our general partner had a 100% general partner interest in us, and Diamondback owned no common units and all of our 107,815,152 outstanding Class B units, representing approximately 71% of our total units outstanding. Diamondback also owns and controls our general partner.

Financial Presentation

Our operations are conducted through, and our operating assets are owned by, the Operating Company. Our assets and operations are reported in two operating business segments: (i) midstream services and (ii) real estate operations. As of December 31, 2019, we own a 29% controlling membership interest in the Operating Company and Diamondback owns, through its ownership of the Operating Company units, a 71% economic, non-voting interest in the Operating Company. However, as required by GAAP, we consolidate 100% of the assets and operations of the Operating Company in our financial statements and reflect a non-controlling interest. As such, our results of operations will not differ materially from the results of operations of the Operating Company. The most noteworthy reconciling items between our consolidated financial statements and the Operating Company’s consolidated financial statements primarily relate to (a) the impact of our election to be treated as a corporation for U.S. federal income tax purposes, and (b) the presentation of noncontrolling interests in the Operating Company. The interests in the Operating Company that are not directly or indirectly owned by us will be reflected as being attributable to noncontrolling interests in our consolidated financial statements.

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 2019 and 2018. A discussion of changes in our results of operations from fiscal year 2017 to fiscal year 2018 has been omitted from this report, but may be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our final prospectus dated May 22, 2019 and filed with the SEC pursuant to Rule 424(b) under the Securities Act on May 24, 2019.

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2019 Transactions and Recent Developments

Initial Public Offering

Prior to the closing on May 28, 2019 of our IPO, Diamondback owned all of the general and limited partner interests in our Predecessor. On May 22, 2019, we priced 38,000,000 common units in our IPO at a price of $17.50 per unit, and on May 23, 2019 our common units began trading on the Nasdaq Global Select Market under the symbol “RTLR”. On May 30, 2019, the underwriters purchased an additional 5,700,000 common units following the exercise in full of their over-allotment option. We received aggregate net proceeds of $719.4 million from the sale of these common units, after deducting the underwriting discount and offering expenses.

At the closing of our IPO, we (i) issued 107,815,152 Class B units representing an aggregate 71% voting limited partner interest in us in exchange for a $1.0 million cash contribution from Diamondback, (ii) issued a general partner interest in us to our general partner in exchange for a $1.0 million cash contribution from our general partner, and (iii) caused the Operating Company to make a distribution of approximately $726.5 million to Diamondback. Diamondback, as the holder of the Class B units, and our general partner, as the holder of our general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1.0 million capital contributions, payable quarterly.

Ajax and Energen Assets

Effective January 1, 2019, Diamondback contributed to our Predecessor certain assets within the Permian Basin that it acquired from Ajax Resources LLC, or Ajax, as part of an upstream acquisition in the fourth quarter of 2018. These assets, which we refer to as the Ajax assets, included 17 water wells, four produced water disposal wells and one related gathering system (35,000 Bbl/d of capacity), a field office, surface land, five hydraulic fracturing pits (4.4 MMBbls of capacity) and one related sourced water transportation system (25,000 Bbl/d of capacity). Prior to their contribution, the Ajax assets were fully integrated into the upstream business acquired from Ajax and used for disposal of produced water generated or obtaining sourced water when drilling. The carrying value of assets included in this contribution was $21.5 million. All of the Ajax assets contributed have estimated remaining useful lives of between 20-30 years.

Effective January 1, 2019, Diamondback contributed to our Predecessor certain assets within the Permian Basin that it acquired from Energen Corporation, or Energen, as part of an upstream acquisition in the fourth quarter of 2018. These assets, which we refer to as the Energen assets, included 56 produced water disposal wells (1.2 MMBbl/d of permitted capacity) and related gathering systems (1.0 MMBbl/d of capacity), an office building located in Midland Texas, surface land and an oil gathering system (16,000 Bbl/d of capacity). Prior to their contribution, the Energen assets were fully integrated into the upstream business acquired from Energen and used for disposal of produced water generated or delivering oil under upstream contracts. The carrying value of assets included in this contribution was $279.0 million, net of $3.0 million in associated asset retirement obligations. All of the Energen assets contributed have estimated remaining useful lives of 30 years.

EPIC and Gray Oak Pipeline Projects

In February 2019, Diamondback funded and our Predecessor acquired a 10% equity interest in each of the EPIC and Gray Oak pipeline projects, which are developing long-haul crude oil pipelines that we expect, following commencement of full commercial operations, will provide us with a steady, oil-weighted cash flow stream. Each of the EPIC and Gray Oak pipelines began interim operations in the second half of 2019, and we expect that both will begin full commercial operations in the second quarter of 2020. These pipelines will provide Diamondback with long-term long-haul transportation for a portion of its Delaware and Midland Basin crude oil production with a total takeaway capacity of up to 200,000 Bbl/d.

Our total capital commitment with respect to our 10% interest in the EPIC joint venture is currently anticipated to be approximately $132 million, which includes $117 million that we contributed in 2019. Our total capital commitment with respect to our 10% interest in the Gray Oak venture is currently anticipated to be approximately $145 million, which includes $115 million that we contributed in 2019.

Wink to Webster Pipeline Project

On July 30, 2019, the Operating Company joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP and Lotus Midstream. The joint venture is developing a long-haul crude oil pipeline together with an affiliate of Enterprise with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations. The Wink to Webster pipeline is expected to begin commercial operations in the first

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half of 2021. Our total capital commitment with respect to our 4% interest in the Wink to Webster joint venture is currently anticipated to be approximately $108 million, which includes $34 million that we contributed in 2019.

OMOG Joint Venture

On November 7, 2019, we and Oryx Midstream, or Oryx, a portfolio company of Stonepeak Infrastructure Partners, through our newly-formed OMOG joint venture, acquired from Reliance Midstream, LLC and other third-party sellers 100% of Reliance Gathering for $356 million, subject to post-closing purchase price adjustments. In accordance with our membership interests in the OMOG joint venture, we and Oryx paid 60% and 40% of the purchase price, respectively. We funded our portion of the purchase price for the acquisition with cash on hand and borrowings under our credit facility. Following completion of the acquisition, Reliance Gathering was renamed Oryx Midland Oil Gathering LLC.

The OMOG joint venture operates a crude oil gathering system with over 230 miles of gathering and regional transportation pipelines and approximately 200,000 barrels of crude oil storage in Midland, Martin, Andrews and Ector Counties, Texas. The system has current throughput of over 100,000 Bbl/d from six oil and gas operators, including Diamondback. Over 160,000 gross acres in Northern Midland Basin are dedicated to the system under long-term, fixed-fee agreements, some of which benefit from minimum volume commitments.

Under the OMOG limited liability company agreement, the OMOG joint venture is managed by a management committee consisting of our designees and Oryx’s designees. Decisions of the management committee require the consent of managers representing at least 70% of the membership interests in OMOG, except for certain decisions that require the consent of managers representing 100% of the membership interests. Oryx is the operator of the gathering system under an operating and management services agreement entered into with the OMOG joint venture.

Amarillo Rattler Joint Venture

On December 20, 2019, we acquired a 50% equity interest in Amarillo Rattler, a joint venture with Amarillo Midstream, LLC, a portfolio company of Arclight Capital Partners. Amarillo Midstream serves as construction manager and operator for this joint venture pursuant to a construction, operations and maintenance agreement entered into with the joint venture. Amarillo Rattler currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. The estimated aggregate capital outlay to the joint venture is anticipated to be approximately $100 million to construct the new processing plant, gas gathering and compression, and regional transportation pipelines. We will be responsible for contributing 50% of the construction budget into the joint venture, in accordance with our 50% interest. We anticipate that the new processing plant will commence full commercial operations in the middle of 2021. Diamondback has contracted for 30,000 Mcf/d of the capacity of the new processing plant pursuant to a gas gathering and processing agreement entered into with the joint venture in exchange for Diamondback’s dedication of certain leasehold interests to that agreement.

Under the Amarillo Rattler limited liability company agreement, Amarillo Rattler is managed by a board of managers consisting of our designees and Amarillo Midstream’s designees. All decisions of the board require the consent of managers representing more than 50% of the membership interests in Amarillo Rattler, except for certain decisions that require the consent of managers representing at least 66⅔% of the membership interests or 100% of the membership interests, as applicable. As of December 31, 2019, we have not made any capital contributions to Amarillo Rattler other than a contribution of approximately 40 acres of land in Martin County, Texas, on which the new processing plant will be built. As of December 31, 2019, our equity interest in Amarillo Rattler LLC was $0.7 million due to legal expenses associated with the investment.

2019 Highlights

Significant Operating Results

The following are significant operating results for the year ended December 31, 2019, and such results as compared with the year ended December 31, 2018:


•	average crude oil gathering volumes were 85,164 Bbl/d, an increase of 80% year over year;


•	average natural gas gathering volumes were 85,283 MMBtu/d, an increase of 117% year over year;

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•	average produced water gathering and disposal volumes were 806,078 Bbl/d, an increase of 186% year over year; and


•	average sourced water gathering volumes were 415,939 Bbl/d, an increase of 65% year over year.

Pipeline Infrastructure Assets

The following tables provide information regarding our gathering, compression and transportation system as of December 31, 2019 and utilization for the quarter ended December 31, 2019:



(miles)⁽¹⁾	Delaware Basin	Midland Basin	Permian Total
Crude oil	104	44	148
Natural gas	148	—	148
Produced water	257	217	474
Sourced water	26	71	97
Total	535	332	867



(capacity/capability)⁽¹⁾	Delaware Basin	Midland Basin	Permian Total	Utilization
Crude oil gathering (Bbl/d)	180,000	56,000	236,000	42	%
Natural gas compression (Mcf/d)	135,000	—	135,000	70	%
Natural gas gathering (Mcf/d)	150,000	—	150,000	56	%
Produced water gathering and disposal (Bbl/d)	1,576,500	1,732,300	3,308,800	27	%
Sourced water (Bbl/d)	120,000	455,000	575,000	83	%


(1)	Does not include assets of EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

Throughput and Crude Oil Volumes

The amount of revenue we generate primarily depends on the volumes of crude oil, natural gas and water for which we provide midstream services. These volumes are affected primarily by changes in the supply of and demand for crude oil and natural gas in the markets served directly or indirectly by our assets. By performing routine maintenance and monitoring our infrastructure, we are able to minimize service interruptions on our gathering, transportation and disposal systems.

Under our commercial agreements, we provide (i) crude oil gathering services, with approximately 181,000 gross dedicated acres, (ii) natural gas gathering and compression services, with approximately 85,000 gross dedicated acres and firm capacity for natural gas attributable to such acreage, (iii) produced water gathering and disposal services, with approximately 397,000 gross dedicated service acres and firm capacity for produced water and flowback water attributable to such acreage, and (iv) sourced water distribution services, with approximately 283,000 gross dedicated service acres. See “Item 8. Financial Statements and Supplementary Data – Note 3. Revenue from Contracts with Customers” for additional information about our commercial agreements with Diamondback.

Because the production rate of a well declines over time, our ability to provide gathering, compression and disposal services, and to maintain or increase the throughput volumes on our midstream systems, is contingent on our customers continually discovering and producing new volumes of crude oil and natural gas and generating produced water. Because sourced water services are largely dependent on well completion, our ability to provide sourced water services is contingent on our customers drilling and completing new wells. We derive substantially all of our revenue from our commercial agreements with Diamondback, which agreements do not contain minimum volume commitments. Our ability to maintain or increase existing throughput volumes on our midstream systems is impacted by:


•	successful drilling activity by our customers on our dedicated acreage and our ability to fund the capital costs required to connect our infrastructure assets to new wells;


•	our ability to utilize the remaining uncommitted capacity on, or add additional capacity to, our infrastructure assets;

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•	our ability to increase throughput volumes on our infrastructure assets by making outlet connections to existing or new third-party pipelines or other facilities, primarily driven by the anticipated supply of and demand for crude oil and natural gas;


•	our ability to identify and execute organic expansion projects to capture incremental volumes from Diamondback and third-parties;


•	our ability to compete for volumes from successful new wells in the areas in which we operate outside of our dedicated acreage; and


•	our ability to gather crude oil and natural gas and provide water services with respect to hydrocarbons produced on acreage that has been released from commitments with our competitors.

We actively monitor producer activity in the areas served by our infrastructure assets to pursue new supply opportunities.

The following table summarizes average throughput and crude oil sales volumes for the periods indicated:



	Year Ended December 31,
(throughput)⁽¹⁾	2019	2018
Crude oil gathering volumes (Bbl/d)	85,164	47,338
Natural gas gathering volumes (MMBtu/d)	85,283	39,252
Produced water gathering and disposal volumes (Bbl/d)	806,078	281,916
Sourced water gathering volumes (Bbl/d)	415,939	252,118


(1)	Does not include volumes from the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

Sources of Our Income

Our results are primarily driven by the volumes of crude oil that we gather, transport and deliver; natural gas that we gather, compress, transport and deliver; water that we source, transport and deliver; and produced water that we gather, transport and dispose of, and the fees we charge per unit of throughput for our midstream services.

Our crude oil infrastructure assets consist of gathering pipelines and metering facilities, which collectively gather crude oil for our customers. Our facilities gather crude oil from horizontal and vertical wells in Diamondback’s ReWard, Spanish Trail, Pecos and Glasscock areas within the Permian. Our natural gas gathering and compression system consists of gathering pipelines, compression and metering facilities, which collectively service the production from Diamondback’s Pecos area assets within the Permian. Our water sourcing and distribution assets consist of water wells, hydraulic fracturing pits, pipelines and water treatment facilities, which collectively gather and distribute water from Permian aquifers to the drilling and completion sites through buried pipelines and temporary surface pipelines. Our produced water gathering and disposal system spans approximately 474 miles and consists of gathering pipelines along with produced water disposal wells and facilities which collectively gather and dispose of produced water from operations throughout Diamondback’s Permian acreage.

We have entered into multiple fee-based commercial agreements with Diamondback, each with an initial term ending in 2034, utilizing our infrastructure assets or our planned infrastructure assets to provide an array of essential services critical to Diamondback’s upstream operations in the Delaware and Midland Basins. Our agreements include substantial acreage dedications.

We have indirect exposure to commodity price risk in that persistent low commodity prices may cause Diamondback or other customers to delay drilling or shut in production, which would reduce the volumes available for gathering and processing by our infrastructure assets. If Diamondback delays drilling or temporarily shuts in production due to persistently low commodity prices or for any other reason, our revenue could decrease, as our commercial agreements do not contain minimum volume commitments.

Under each of our commercial agreements (other than the FERC-regulated crude oil gathering services agreement), the volumetric fees we charge are adjusted each calendar year by the amount of percentage change, if any, in the consumer price index from the preceding calendar year. No adjustment will be made if the percentage change would result in a fee below the initial fee set forth in the applicable commercial agreement and any adjustment to the volumetric fees shall not exceed 3% of the then-current fee. Further, the total adjustment of the fees shall never result in a cumulative volumetric fee adjustment of more than 30% of the initial fees set forth in the applicable commercial agreement.

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Principal Components of Our Cost Structure

General and Administrative

At the closing of our IPO, we entered into to a services and secondment agreement with Diamondback, which we refer to the services and secondment agreement, under which we pay fees to Diamondback with respect to certain operational services Diamondback provides in support of our operations. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner 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 general partner is entitled to determine the expenses that are allocable to us.

Depreciation, Amortization and Accretion

This represents the depreciation, amortization and accretion on the assets and liabilities of the Operating Company.

Income Taxes

Prior to our IPO, our Predecessor was organized as a disregarded entity for income tax purposes. As a result, our Predecessor’s sole owner, Diamondback, was responsible for federal income taxes on the Predecessor’s taxable income. Subsequent to our IPO, we are subject to federal income taxes at the corporate statutory rate of 21%.

We are subject to the Texas margin tax. For the year ended December 31, 2019, we accrued $0.2 million for Texas margin tax payable pursuant to the tax sharing agreement with Diamondback.

Other income (expense), net

Interest income

This represents the interest received on our cash.

Interest expense

We have financed a portion of our working capital requirements, capital expenditures and acquisitions with borrowings under our revolving credit facility. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense. In addition, we include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Income (loss) from equity method investments

This represents our proportional income (loss) from our equity method investments.

Factors Affecting the Comparability of Our Financial Results

Our future results of operations may not be comparable to our Predecessor’s historical results of operations for the reasons described below:

Contribution of Midstream Assets

During the period from 2014 through 2017, Diamondback constructed and/or acquired various midstream and related assets located in the Delaware and Midland Basins, which Diamondback contributed to our Predecessor during fiscal years 2016 and 2017. These assets included 20 produced water disposal wells and related gathering systems, two oil gathering systems, surface land, and other pipelines not yet placed into service. Prior to their contribution, these assets were fully integrated into Diamondback’s upstream operations.

Effective February 28, 2017, Diamondback contributed to our Predecessor certain midstream assets in the Pecos area within the Permian that it acquired from Brigham Resources Operating, LLC, Brigham Resources Midstream, LLC and other

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unrelated third parties, which we refer to collectively as Brigham. These assets included five produced water disposal wells and seven hydraulic fracturing ponds across one main gathering system, and various pipelines and compression assets related to a gas gathering system and an oil gathering system, the majority of which were not yet in service. Prior to their contribution from Diamondback, these assets were owned by Brigham and were fully integrated into Brigham’s upstream operations where the assets were already in service. All of the assets contributed have estimated remaining useful lives of between 20-30 years.

Effective January 1, 2018, Diamondback contributed to our Predecessor the sourced water assets located within the Permian Basin. These assets included numerous sourced water wells and 28 hydraulic fracturing ponds, located across nine sourced water transportation systems, that had previously been used to store and transport sourced water for Diamondback’s drilling operations. All of the Ajax assets contributed have estimated remaining useful lives of between 20-30 years.

Throughout 2018, Diamondback continued to assist our Predecessor in the construction of various other gathering assets, which included additional oil and natural gas and produced water pipelines, produced water disposal wells and hydraulic fracturing ponds. These assets were never used as part of upstream operations, but were contributed immediately upon completion.

Effective January 1, 2019, Diamondback contributed to our Predecessor the Ajax assets within the Permian Basin that it acquired from Ajax as part of an upstream acquisition in the fourth quarter of 2018. These assets included 17 water wells, four produced water disposal wells and one related gathering system (35,000 Bbl/d of capacity), a field office, surface land, five hydraulic fracturing pits (4.4 MMBbls of capacity) and one related sourced water transportation system (25,000 Bbl/d of capacity). Prior to their contribution, these assets were fully integrated into the upstream business acquired from Ajax and used for disposal of produced water generated or water sourcing when drilling. All of the Ajax assets contributed have estimated remaining useful lives of between 20-30 years.

Effective January 1, 2019, Diamondback contributed to our Predecessor the Energen assets within the Permian Basin that it acquired from Energen, as part of an upstream acquisition in the fourth quarter of 2018. These assets included 56 produced water disposal wells (1.2 MMBbl/d of permitted capacity) and related gathering systems (1.0 MMBbl/d of capacity), an office building located in Midland, Texas, surface land and an oil gathering system (16,000 Bbl/d of capacity). Prior to their contribution, these assets were fully integrated into the upstream business acquired from Energen and used for disposal of produced water generated or delivering oil under upstream contracts. All of the Energen assets contributed have estimated remaining useful lives of 30 years.

Contribution of Fasken Center

Effective January 31, 2018, Diamondback contributed to our Predecessor all of its membership interest in its wholly owned subsidiary, Tall City Towers LLC, or Tall Towers, which acquired from Fasken Midland LLC on January 31, 2018 certain real property consisting of land and two office towers in Midland, Texas, which we refer to as the Fasken Center, for a purchase price of approximately $110.0 million. With the asset contribution, our Predecessor also acquired third-party leases, which were valued as part of Diamondback’s purchase price. All of the assets contributed have estimated remaining useful lives of between 15-30 years.

Equity Method Investments

In 2019, we acquired equity interests in the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler and OMOG joint ventures. Each of these joint ventures is accounted for using the equity method. The following table sets forth the equity method investment interests acquired during 2019:



	Ownership Interest		Acquisition Date	Cumulative Capital Contributions to Date		Anticipated Remaining Capital Commitment
				(In thousands)
EPIC Crude Holdings, LP	10	%	February 1, 2019	$	117,039	$	14,927
Gray Oak Pipeline, LLC	10	%	February 15, 2019	$	114,521	$	30,725
Wink to Webster Pipeline LLC	4	%	July 30, 2019	$	33,794	$	74,206
OMOG JV LLC	60	%	October 1, 2019	$	218,555	$	—
Amarillo Rattler, LLC	50	%	December 20, 2019	$	—	$	50,000

See “–2019 Transactions and Recent Developments” above for further discussion of the our equity method investments.

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Revenues

Prior to their contribution to our Predecessor, infrastructure assets were part of the integrated operations of Diamondback and were financed from cash flows from operations and funding from Diamondback. Commencing January 1, 2016, our Predecessor began to earn revenues under our long-term commercial agreements with Diamondback and began receiving separate fixed fees for the midstream services that we provide.

Our Predecessor’s real estate assets were contributed by Diamondback effective January 31, 2018 and we earn revenue from these assets through various lease agreements.

Operating Expenses

At the closing of our IPO, we entered into the services and secondment agreement with Diamondback under which we pay fees to Diamondback with respect to certain operational services Diamondback provides in support of our operations. Our Predecessor recorded direct costs of running our businesses as well as certain costs allocated from Diamondback. As such, there are differences in the results of our operations between our Predecessor’s historical financial statements and our financial statements.

General and Administrative Expenses

Our Predecessor’s general and administrative expense included an allocation of charges for the management and operation of our assets by Diamondback for general and administrative services, such as information technology, treasury, accounting, human resources and legal services and other financial and administrative services. Following the completion of our IPO, Diamondback charges us a combination of direct and allocated charges for general and administrative services pursuant to our partnership agreement and the services and secondment agreement.

In addition, as compared to our Predecessor, we incur incremental general and administrative expenses attributable to being a publicly traded partnership, which include expenses associated with annual, quarterly and current reporting with the SEC, tax return preparation, Sarbanes-Oxley compliance, listing on Nasdaq, independent auditor fees, legal fees, investor relations expenses, transfer agent and registrar fees, incremental salary and benefits costs of seconded employees, outside director fees and insurance expenses. These incremental general and administrative expenses and the variable component of the general and administrative costs that we are incurring under the services and secondment agreement are not reflected in our historical financial statements.

Financing

There are differences in the way we finance our operations as compared to the way our Predecessor historically financed operations. Historically, our Predecessor’s operations were financed as part of Diamondback’s integrated operations. Our sources of liquidity following our IPO include cash generated from operations and borrowings under our revolving credit facility.

Income Taxes

Income tax expense includes U.S. federal and state taxes on operations, as applicable. Prior to our IPO, our Predecessor was organized as a disregarded entity for income tax purposes. As a result, our Predecessor’s sole owner, Diamondback, was responsible for federal income taxes on our Predecessor’s taxable income. Even though we are organized as a limited partnership under state law, we are treated as a corporation for U.S. federal income tax purposes and are subject to U.S. federal and state income tax at corporate rates, subsequent to the May 24, 2019 effective date of our election to be treated as a corporation. As such, our net income for the year ended December 31, 2019 reflects a provision for income taxes for the period subsequent to our IPO and, for the periods prior to our IPO, net income of the Predecessor reflects on a pro forma basis, a provision for income taxes as if our Predecessor had been treated as a corporation for U.S. federal income tax purposes.

Other Factors Impacting Our Business

We expect our business to continue to be affected by the following key factors. Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

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Supply and Demand for Crude Oil and Natural Gas

We currently generate a substantial portion of our revenues under fee-based commercial agreements with Diamondback. These contracts promote cash flow stability and minimize our direct exposure to commodity price fluctuations, since we generally do not own any of the crude oil, natural gas or water that we gather and do not engage in the trading of crude oil or natural gas. However, the volumetric fees we charge are adjusted each calendar year by the amount of percentage change, if any, in the consumer price index from the preceding calendar year. No adjustment will be made if the percentage change would result in a fee below the initial fee set forth in the applicable commercial agreement and any adjustment to the volumetric fees shall not exceed 3% of the then-current fee. Further, the total adjustment of the fees shall never result in a cumulative volumetric fee adjustment of more than 30% of the initial fees set forth in the applicable commercial agreement.

Additionally, commodity price fluctuations indirectly influence our activities and results of operations over the long-term, since they can affect production rates and investments by Diamondback and third-parties in the development of new crude oil and natural gas reserves. Generally, drilling and production activity will increase as crude oil and natural gas prices increase. Our throughput volumes depend primarily on the volumes of crude oil and natural gas produced by Diamondback in the Permian and, with respect to sourced water, the number of wells drilled and completed. Commodity prices are volatile and influenced by numerous factors beyond our or Diamondback’s control, including the domestic and global supply of and demand for crude oil and natural gas. The commodities trading markets, as well as other supply and demand factors, may also influence the selling prices of crude oil and natural gas. Furthermore, our ability to execute our growth strategy in the Permian will depend on crude oil and natural gas production in that area, which is also affected by the supply of and demand for crude oil and natural gas.

Regulatory Compliance

The regulation of crude oil and natural gas gathering and transportation and water services activities by federal and state regulatory agencies has a significant impact on our business. Our operations are also impacted by new regulations, which have increased the time that it takes to obtain required permits.

Additionally, increased regulation of crude oil and natural gas producers in our areas of operation, including regulation associated with hydraulic fracturing, could reduce regional supply of crude oil, natural gas and water and, therefore, throughput on our infrastructure assets.

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Results of Operations for the Year Ended December 31, 2019 and 2018

The following table sets forth selected historical operating data for the periods indicated:



	Year Ended December 31,
	2019			2018
Operating Results:	(In thousands, except operating data)
Revenues:
Revenues—related party	$	409,120		$	169,396
Revenues—third party	24,324			3,292
Rental income—related party	4,771			2,383
Rental income—third party	7,890			8,125
Other real estate income—related party	379			228
Other real estate income—third party	1,189			1,043
Total revenues	447,673			184,467
Costs and expenses:
Direct operating expenses	106,311			33,714
Cost of goods sold (exclusive of depreciation and amortization)	62,856			38,852
Real estate operating expenses	2,643			1,872
Depreciation, amortization and accretion	42,336			25,134
General and administrative expenses	12,663			1,999
Loss on disposal of property, plant and equipment	1,524			2,577
Total costs and expenses	228,333			104,148
Income from operations	219,340			80,319
Other expense:
Interest expense, net	(1,039		)	—
Loss from equity method investments	(6,329		)	—
Total other expense	(7,368		)	—
Net income before income taxes	211,972			80,319
Provision for income taxes	26,253			17,359
Net income after taxes	$	185,719		$	62,960

Net income before initial public offering	65,995

Net income subsequent to initial public offering	119,724
Net income attributable to non-controlling interest subsequent to initial public offering	90,922
Net income attributable to Rattler Midstream LP	$	28,802

Operating Data:
Throughput⁽¹⁾
Crude oil gathering volumes (Bbl/d)	85,164			47,338
Natural gas gathering volumes (MMBtu/d)	85,283			39,252
Produced water gathering and disposal volumes (Bbl/d)	806,078			281,916
Sourced water gathering volumes (Bbl/d)	415,939			252,118


(1)	Does not include volumes from the EPIC, Gray Oak, Wink to Webster, Amarillo Rattler or OMOG joint ventures.

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Comparison of the Years Ended December 31, 2019 and 2018

Revenues

Revenues for the years ended December 31, 2019 and 2018 were $447.7 million and $184.5 million, respectively. The increase of $263.2 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 relates to increased volumes largely due to the contribution of certain crude oil gathering, produced water disposal wells and land and buildings that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us effective on January 1, 2019, as well as the additional build out of historical systems. Produced water gathering and disposal revenues increased by $203.5 million, sourced water gathering revenues increased by $38.2 million, crude oil gathering revenues increased by $11.2 million, natural gas gathering revenues increased by $7.9 million and real estate revenue increased by $2.4 million for year ended December 31, 2019.

Direct Operating Expenses

Direct operating expenses for the years ended December 31, 2019 and 2018 were $106.3 million and $33.7 million, respectively. The increase of $72.6 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily due to increased volumes largely attributable to the contribution of certain crude oil gathering, produced water disposal wells and land and buildings that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us effective January 1, 2019, as well as the additional build out of historical systems.

Cost of Goods Sold

Cost of goods sold (exclusive of depreciation and amortization) for the years ended December 31, 2019 and 2018 was $62.9 million and $38.9 million, respectively. The increase of $24.0 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 relates to the increased build out of historical sourced water systems of the Operating Company and the increased volumes across existing sourced water systems.

Real Estate Operating Expenses

Real estate operating expenses for the years ended December 31, 2019 and 2018 were $2.6 million and $1.9 million, respectively. The increase of $0.8 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 primarily relates to the addition of new tenants and the contribution of a field office from Diamondback.

Depreciation, Amortization and Accretion

Depreciation, amortization and accretion for the years ended December 31, 2019 and 2018 was $42.3 million and $25.1 million, respectively. The increase of $17.2 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily due to asset contributions from Diamondback and further development of existing gathering, transportation and disposal systems.

General and Administrative Expenses

General and administrative expenses for the years ended December 31, 2019 and 2018 were $12.7 million and $2.0 million, respectively. The increase of $10.7 million for the year ended December 31, 2019 as compared to the year ended December 31, 2018 was primarily due to increased shared service allocations and additional professional service fees attributable to business growth, the IPO, and the contribution of additional midstream assets.

Loss on Disposal of Property, Plant and Equipment

Loss on disposal of property, plant and equipment was $1.5 million for the year ended December 31, 2019 due to weather damage at certain produced water disposal facilities. The damage totaled $7.5 million, for which we expect insurance proceeds of $6.0 million. Loss on disposal of property, plant and equipment was $2.6 million for the year ended December 31, 2018 and was due to the exchange of interest in produced water disposal assets.

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Interest Expense, Net

Net interest expense for the year ended December 31, 2019 was $1.0 million. The increase of $1.0 million for the year ended December 31, 2019 from no interest expense for the year ended December 31, 2018 was primarily due to the Operating Company entering into the credit agreement on May 28, 2019 and subsequent borrowings thereunder.

Loss from Equity Method Investments

Loss from equity method investments was $6.3 million for the year ended December 31, 2019. There was no income or loss from equity method investments for the year ended December 31, 2018. The increase for the year ended December 31, 2019 from the year ended December 31, 2018 was related to interest expense incurred on Gray Oak’s promissory note and expenses incurred on investments not yet in service, partially offset by income from our equity method investments that began initial operations in 2019.

Provision for Income Taxes

We recorded income tax expense of $26.3 million and $17.4 million for the years ended December 31, 2019 and 2018, respectively. The $8.9 million increase in our income tax provision from the year ended December 31, 2018 to the year ended December 31, 2019 was primarily due to an increase in pre-tax income for the year ended December 31, 2019, partially offset by the impact of net income attributable to the non-controlling interest for the 2019 period subsequent to our IPO. Total income tax expense for the year ended December 31, 2019 differed from amounts computed by applying the federal statutory tax rate to pre-tax income from continuing operations for the period primarily due to net income attributable to the non-controlling interest.

Non-GAAP Financial Measures

Adjusted EBITDA

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The following table presents a reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP financial measures for each of the periods indicated:



	Year Ended December 31,
	2019			2018
	(In thousands)
Reconciliation of Net Income to Adjusted EBITDA:
Net income	$	185,719		$	62,960
Depreciation, amortization and accretion	42,336			25,134
Interest expense, net of amount capitalized	1,039			—
Interest expense related to equity method investments	1,005			—
Depreciation related to equity method investments	1,636			—
Non-cash unit-based compensation expense	5,208			—
Other non-cash transactions	1,528			—
Provision for income taxes	26,253			17,359
Adjusted EBITDA	264,724			$	105,453
Less: Adjusted EBITDA prior to the IPO	(100,743		)
Adjusted EBITDA subsequent to the IPO	163,981
Less: Adjusted EBITDA attributable to non-controlling interest	(116,685		)
Adjusted EBITDA attributable to Rattler Midstream LP	$	47,296

Liquidity and Capital Resources

Overview

Prior to our IPO, our sources of liquidity were based on cash flow from operations and funding from Diamondback.

Our sources of liquidity following our IPO include cash generated from operations, borrowings under the credit agreement and, if necessary, the issuance of additional equity or debt securities. We believe that cash generated from these sources will be sufficient to meet our short-term working capital requirements and long-term capital expenditure requirements and to make quarterly cash distributions. We do not have any commitment from Diamondback, our general partner or any of their respective affiliates to fund our cash flow deficits or provide other direct or indirect financial assistance to us.

At the closing of the IPO, the board of directors of our general partner adopted a policy for us to distribute cash distributions to common unitholders of record on the applicable record date of $0.25 per common unit after the end of each quarter beginning with the quarter ending September 30, 2019. Our first distribution of $0.34, included available cash for the period from May 28, 2019, the date of the close of our IPO, through September 30, 2019. On February 13, 2020, the board of directors of our general partner revised our cash distribution policy to provide that cash distributions will be made to common unitholders of record on the applicable record date of $0.29 per common unit for each quarter ending after December 31, 2019.

The board of directors of our general partner may change our distribution policy at any time and from time to time.

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. Our partnership agreement does not require us to pay distributions to our common unitholders on a quarterly or other basis.

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The following table presents cash distributions approved by the board of directors of our general partner for the periods presented:



Declaration Date	Quarter	Amount per Common Unit⁽¹⁾		Payment Date
October 31, 2019	Q3 2019	$	0.34	November 22, 2019
February 13, 2020	Q4 2019	$	0.29	March 10, 2020


(1)	Distributions are shown for the quarter in which they were generated; provided, however, the Q3 2019 distribution also includes amounts attributable to Q2 2019 commencing upon the closing of our IPO.


(2)	The Q4 2019 distribution is payable on March 10, 2020 to unitholders of record at the close of business on March 3, 2020.

The Operating Company’s Credit Agreement

We, as parent, and the Operating Company, as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks, including Wells Fargo Bank, National Association, as lenders party thereto, which we refer to as the credit agreement.

The credit agreement provides for a revolving credit facility in the maximum amount of $600.0 million. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The loan is guaranteed by us and Tall Towers, Rattler OMOG LLC and Rattler Ajax Processing LLC and is secured by substantially all of our, the Operating Company and the other guarantors’ assets. As of December 31, 2019, we had $424.0 million of outstanding borrowings, and $176.0 million available for future borrowings under the credit agreement.

The outstanding borrowings under the credit agreement bear interest at a per annum rate elected by us that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum 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.

The credit agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case with us, the Operating Company and our restricted subsidiaries. The covenants are subject to exceptions set forth in the credit agreement, including an exception allowing the Operating Company or us to issue unsecured debt securities, and an exception allowing payment of distributions if no default exists. The credit agreement may be used to fund capital expenditures, to finance working capital, for general company purposes, to pay fees and expenses related to the credit agreement, and to make distributions permitted under the credit agreement.

The credit agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:



Financial Covenant		Required Ratio
Consolidated Total Leverage Ratio		Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the credit agreement) is applicable, then not greater than 5.25 to 1.00)
Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the credit agreement) is made		Not greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the credit agreement)		Not less than 2.50 to 1.00

For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the credit agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019.

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As of December 31, 2019, the Operating Company was in compliance with all financial covenants under the credit agreement. The lenders may accelerate all of the indebtedness under the credit agreement upon the occurrence and during the continuance of any event of default. The credit agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants and certain affimative covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the credit agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

Cash Flows

Net cash provided by operating activities, investing activities and financing activities for the years ended December 31, 2019 and 2018 were as follows:



	Year Ended December 31,
	2019			2018
	(In thousands)
Net cash provided by operating activities	$	218,193		$	173,431
Net cash used in investing activities	(578,369		)	(164,876		)
Net cash provided by financing activities	362,245			1
Net increase in cash	$	2,069		$	8,556

Operating Activities

Net cash provided by operating activities increased by $44.8 million during the year ended December 31, 2019 compared to the year ended December 31, 2018. The increase was due to increased operations as additional assets were placed into service and the contribution of certain crude oil gathering, produced water disposal wells and land and buildings that Diamondback acquired in the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us effective January 1, 2019.

Investing Activities

Net cash used in investing activities was $578.4 million and $164.9 million during the years ended December 31, 2019 and 2018, respectively, and primarily related to additions to property, plant and equipment and contributions to our EPIC, Gray Oak, Wink to Webster, OMOG and Amarillo Rattler equity method investments. See “Item 8. Financial Statements and Supplementary Data–Note 8. Equity Method Investments.”

Financing Activities

Net cash used in financing activities was $362.2 million during the year ended December 31, 2019, primarily related to net proceeds of $719.4 million from our IPO of common units, a contribution of $1.0 million from our general partner for its general partner interest in us, a contribution of $1.0 million from Diamondback for its Class B units and borrowings, net of repayment of $424.0 million, partially offset by distributions to our unitholders of $778.1 million during 2019.

There was $1 thousand net cash provided by financing activities during the year ended December 31, 2018.

Capital Contributions and Capital Expenditures

The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities.

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

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period, the Operating Company made capital expenditures of $241.8 million, comprised of $152.8 million million related to produced water disposal assets, $27.1 million million were related to crude oil gathering assets, $38.1 million million were related to natural gas gathering assets and $23.8 million million were related to sourced water assets.

For the year ended December 31, 2018, the total capital contributions by Diamondback to our Predecessor were $171.2 million, of which $110.0 million related to Tall Towers, $1.3 million related to a field office, $1.5 million related to land, $32.8 million related to sourced water assets, $18.2 million related to produced water disposal assets, $6.0 million related to sourced water inventory and $1.4 million in additional assets and liabilities, net, related to operations. During this period, the Operating Company made capital expenditures of $164.9 million, comprised of $114.7 million related to produced water disposal assets, $16.3 million related to crude oil gathering assets, $30.1 million related to natural gas gathering assets, $3.7 million related to sourced water gathering systems and $0.1 million related to land.

We estimate that total capital expenditures related to midstream assets for the year ending December 31, 2020 will be between $200 million and $225 million. Our estimated capital expenditures do not include our anticipated total capital commitments related to our equity method investments of approximately $169.9 million.

Contractual Obligations

The following table summarizes our contractual obligations and commitments as of December 31, 2019:



	Payments Due by Period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Credit agreement⁽¹⁾	$	424,000	$	—	$	—	$	424,000	$	—
Commitment fees under the credit agreement⁽²⁾	1,938		440		880		618		—
Operating leases ⁽³⁾	315		315		—		—		—
Total	$	426,253	$	755	$	880	$	424,618	$	—


(1)	Includes the outstanding principal amount under the revolving credit facilities, the table does not include interest expense or other fees payable under this floating rate facility as we cannot predict the timing of future borrowings and repayments or interest rates to be charged.


(2)	This table reflects only the minimum amount of commitment fees due, which as of December 31, 2019 includes a commitment fee equal to 0.250% per year of the unused portion of the borrowing base of our credit agreement.


(3)	Operating lease obligations represent future commitments for equipment leases.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. Below, we have provided expanded discussion of our most critical accounting estimates, assumptions, judgments and uncertainties that are inherent in our application of GAAP. We identify certain accounting policies as critical based on, among other things, their impact on the portrayal of our financial condition, results of operations or liquidity, and the degree of difficulty, subjectivity and complexity in their application. Critical accounting policies cover accounting matters that are inherently uncertain because the future resolution of such matters is unknown. See Note 2. Summary of Significant Accounting Policies of the Notes to the Consolidated Financial Statements included elsewhere in this Annual Report for additional information regarding these accounting policies.

Use of Estimates

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. 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. Nevertheless, actual results may differ significantly from our estimates.

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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 estimates of revenue accruals, valuation of sourced water inventory, fair value of long-lived assets, including intangible lease assets, asset retirement obligations, and estimate of income taxes.

Revenue Recognition

We provide gathering and compression and water handling and treatment services under fee-based contracts based on throughput. Under these arrangements, we receive fees for gathering oil and gas products, compression services, and water handling, disposal, and treatment services. The revenue we earn from these arrangements is directly related to (i) in the case of natural gas gathering and compression, the volumes of metered natural gas that we gather, compress, transport and deliver to other transmission delivery points, (ii) in the case of oil gathering, the volumes of metered oil that we gather, transport and deliver to other transmission delivery points, (iii) in the case of sourced water services, the quantities of water that we source, transport, and deliver to our customers for use in their well drilling and completion operations, (iv) in the case of produced water gathering and disposal services, the quantities of produced water gathered, transported and disposed of for our customers. We recognize revenue when we satisfy a performance obligation by delivering a service to a customer. We earn substantially all of its midstream revenues from commercial agreements with Diamondback and its affiliates. We recognize rental revenue from tenants on a straight-line basis over the lease term when collectability is reasonably assured and the tenant has taken possession or controls the physical use of the leased asset. Rental income-related party is comprised of revenues earned from lease agreements with Diamondback and its affiliates. Tenant recoveries related to reimbursement of real estate taxes, insurance, repairs and maintenance and other operating expenses are recognized as revenue in the period the applicable expenses are incurred. The reimbursements are recognized and presented gross, as we are generally the primary obligor with respect to purchasing goods and services from third-party suppliers, and have discretion in selecting the supplier and bear the associated credit risk.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost upon acquisition and evaluated for potential impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable through estimated future undiscounted cash flows. Expenditures which extend the useful lives of existing property, plant and equipment are capitalized.

When properties are retired or otherwise disposed, the related cost and accumulated depreciation are removed from the respective accounts and any gain or loss on disposition is recognized in the consolidated statement of operations.

Depreciation, Amortization and Accretion

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

Equity Method Investments

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

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

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Asset Retirement Obligations

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

Income Taxes

On May 24, 2019, we elected to be treated as a corporation for U.S. federal income tax purposes. 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 bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

We are subject to margin tax in the state of Texas pursuant to a tax sharing agreement with Diamondback, as discussed further in Note 14—Income Taxes of our consolidated financial statements included elsewhere in this Annual Report. In addition to the 2019 tax year, the Predecessor’s 2016 through 2018 tax years, the periods during which the Predecessor’s sole owner, Diamondback, was responsible for federal income taxes on the Predecessor’s taxable income, remain open to examination by tax authorities. As of December 31, 2019, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. We are continuing our practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the year ended December 31, 2019, there was no interest or penalties associated with uncertain tax positions recognized in our consolidated financial statements.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2019 and 2018. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. We have experienced inflationary pressure on the cost of labor and equipment as increasing crude oil and natural gas prices have increased development activity in our areas of operations, especially in the Delaware Basin.

Recent Accounting Pronouncements

For information regarding recent accounting pronouncements, See Note 2–Summary of Significant Accounting Policies included in Notes to the Consolidated Financial Statements included elsewhere in this Annual Report.

Off-Balance Sheet Arrangements

None.

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.

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Commodity Price Risk

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

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

Credit Risk

We are subject to counterparty credit risk related to our midstream commercial contracts, lease agreements and related to our 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. 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. Nonperformance by a counterparty could result in significant financial losses.

Interest Rate Risk

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

As of December 31, 2019, we had $424.0 million of outstanding borrowings and $176.0 million available for future borrowings under the credit agreement. The weighted average interest rate on borrowings under the credit agreement was 2.98% as of December 31, 2019. An increase or decrease of 1% in the interest rate would have a corresponding increase or decrease in our interest expense of approximately $4.2 million based on the $424.0 million outstanding under the credit agreement as of December 31, 2019.

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

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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, 2019, 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, 2019, our disclosure controls and procedures are effective.

Management’s Annual Report on Internal Control Over Financial Reporting and Attestation Report of the Registered Public Accounting Firm. This Annual Report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the company’s registered public accounting firm due to a transition period established by the rules of the SEC for newly public companies.

Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2019 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

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 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, 2020. 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.

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Name	Age	Position With Our General Partner
Travis D. Stice	58	Chief Executive Officer and Director
Kaes Van't Hof	33	President and Director
Teresa L. Dick	50	Chief Financial Officer, Executive Vice President and Assistant Secretary
Matt Zmigrosky	41	Executive Vice President, General Counsel and Secretary
Steven E. West	59	Chairman of the Board
Laurie H. Argo	47	Director
Arturo Vivar	57	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 33 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 33-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 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. Since March 2019, she has also served as Diamondback’s Executive Vice President and Chief Accounting Officer. Ms. Dick served as Diamondback’s Executive Vice President and Chief Financial Officer from February 2017 to February 2019, Assistant Secretary from October 2012 to February 2019, Chief Financial Officer and Senior Vice President and Assistant Secretary from February 2007 to November 2009 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 and Senior Vice President 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.

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

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

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

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

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

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

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

Director Independence

The board of directors of our general partner has five directors, three of whom are independent as defined under the independence standards established by Nasdaq and the Exchange Act. Steven E. West, Laurie H. Argo and Arturo Vivar serve as the independent members of the board of directors of our general partner. Although a majority of the board of directors of our

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general partner is independent, Nasdaq does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner or to establish a compensation committee or a nominating and corporate governance committee. However, our general partner is required to have an audit committee of at least three members, and all its members are required to meet the independence and experience standards established by Nasdaq and the Exchange Act.

Board Leadership Structure and Role in Risk Oversight

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

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

The board of directors of our general partner believes that full and open communication between management and the board is essential for effective risk management and oversight. The Chairman of the board of directors of our general partner meets regularly with the Chief Executive Officer and the Chief Financial Officer to discuss strategy and risks facing us. Executive officers may attend the board meetings of our general partner and are available to address any questions or concerns raised by the board on risk management-related and any other matters. Other members of our management team periodically 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, our 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 2019, the board of directors of our general partner met four 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 2019.

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.

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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 conflict matters, compensation matters and nominating and corporate governance matters.

Audit Committee

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

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

Conflicts Committee

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

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

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of Diamondback. All of our general partner’s executive officers that are responsible for managing our day-to-day affairs are also current executive officers of Diamondback.

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

The executive officers of our general partner, as well as the employees of Diamondback who provide services to us, may participate in employee benefit plans and arrangements sponsored by Diamondback, including plans that may be established in the future. Certain of our general partner’s executive officers and employees and certain employees of Diamondback who provide services to us currently hold grants under Diamondback’s and Viper’s equity incentive plans. Except with respect to any awards that may be granted under the LTIP, the executive officers of our general partner do not receive separate amounts of compensation in relation to the services they provide to us. In accordance with the terms of our partnership agreement and the operational service and secondment agreement, we reimburse Diamondback for compensation related expenses attributable to the portion of the executive’s time dedicated to providing services to us. Although we bear an allocated portion of Diamondback’s costs of providing compensation and benefits to employees who serve as executive officers of our general partner, we have no control over such costs and do not establish nor direct the compensation policies or practices of Diamondback. Except with respect to awards granted under the LTIP, compensation paid or awarded by us in 2019 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 2020 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 set forth in Diamondback’s 2020 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 2019, 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.

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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 in shares of our common units), proscribe and interpret the terms and provisions of each award agreement (the terms of which may vary), accelerate the vesting provisions associated with an award, delegate duties under the LTIP and execute all other responsibilities permitted or required under the LTIP.

Amendment or Termination of Long-Term Incentive Plan

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

Change of Control

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

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

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

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

The following table sets forth the aggregate dollar amount of all fees paid to each of the non-employee directors of our general partner during 2019 for their services on the board:



Name	Fees Earned or Paid in cash(a)		Unit Awards(b)		Total
Steven E. West^(c)	$	50,000	$	103,195	$	153,195
Laurie H. Argo^(c)	46,667		103,195		149,862
Arturo Vivar^(c)	46,667		103,195		149,862


^(a)	This column reflects the value of a director’s annual retainer.


^(b)	The amount in this column represents the aggregate grant date fair value of phantom units granted in the fiscal year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification Topic 718, “Compensation - Stock Compensation.” Distribution equivalent rights are not reflected in the aggregate grant date fair value of phantom unit awards.


^(c)	Each of Ms. Argo and Messrs. West and Vivar received a grant of 5,714 phantom units on May 22, 2019, which will vest and settle on May 22, 2020, pursuant to the LTIP, with each unit having a grant date fair value of $18.06. 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. Mr. 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 2020 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, a director and executive officer of our general partner, are also directors and executive officers of Diamondback. However, all compensation decisions with respect to Messrs. Van’t Hof and Stice are made by Diamondback and Messrs. Van’t Hof and Stice do not receive any compensation directly from us or our general partner except for awards under our LTIP. As described in “– Compensation Discussion and Analysis,” decisions regarding the compensation of our general partner’s executive officers are made by Diamondback. See “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” and “Item 13. Certain Relationships and Related Transactions, and Director Independence” for more information about relationships among us, our general partner and Diamondback.

Compensation Policies and Practices as They Relate to Risk Management

We do not have any employees. We are managed and operated by the directors and officers of our general partner and employees of Diamondback perform services on our behalf. See “–Compensation Discussion and Analysis” and “Items 1 and 2. Business and Properties–Our Relationship with Diamondback” for more information about this arrangement. For an analysis of any risks arising from Diamondback’s compensation policies and practices, see Diamondback’s 2020 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, 2020 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⁾	90,695	*
Kaes Van’t Hof⁽³⁾	—	—
Teresa L. Dick⁽⁴⁾	8,000	*
Matt Zmigrosky⁽⁵⁾	3,000	*
Laurie H. Argo⁽⁶⁾	500	*
Arturo Vivar⁽⁶⁾	14,250	*
Steven E. West⁽⁶⁾	28,550	*
All directors and executive officers of our general partner as a group (7 persons)	144,995	*


*	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, 2020 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, 2020 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 43,700,000 common units outstanding as of January 31, 2020. 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, 2020 or within 60 days of January 31, 2020. 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 114,286 phantom units, that are scheduled to vest in five equal installments beginning on May 28, 2020.


(3)	Excludes 1,142,857 phantom units, that are scheduled to vest in five equal installments beginning on May 28, 2020.


(4)	Excludes 57,143 phantom units, that are scheduled to vest in five equal installments beginning on May 28, 2020.


(5)	Excludes 22,857 phantom units, that are scheduled to vest in five equal installments beginning on May 28, 2020.


(6)	Excludes 5,714 phantom units, that are scheduled to vest on May 22, 2020.

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The following table sets forth, as of January 31, 2020, 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⁾	392,042	*
Kaes Van’t Hof⁽³⁾	13,548	*
Teresa L. Dick⁽⁴⁾	37,547	*
Matt Zmigrosky⁽⁵⁾	4,054	*
Laurie H. Argo	—	—
Arturo Vivar	—	—
Steven E. West⁽⁶⁾	7,461	*
All directors and executive officers as a group (7 persons)	454,652	*


*	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, 2020 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, 2020, 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 67,805,707 shares of common stock outstanding as of January 31, 2020. 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, 2020 or within 60 days of January 31, 2020. 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 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 6,797 restricted stock units, that are scheduled to vest on February 21, 2020 and (ii) 10,986 restricted stock units, that are scheduled to vest on March 1, 2020. Excludes 10,986 restricted stock units, that are scheduled to vest on March 1, 2021. Also excludes (i) 44,460 performance-based restricted stock units awarded to Mr. Stice on February 16, 2017, that will vest effective December 31, 2019 (representing 200% vesting of the originally reported amount) subject to 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, 2019 by Diamondback’s compensation committee, (ii) 30,585 performance-based restricted stock units awarded to Mr. Stice on February 13, 2018, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending December 31, 2020, and (iii) 49,436 performance-based restricted stock units awarded to Mr. Stice on March 1, 2019, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021.

(3)

Includes (i) 1,333 restricted stock units, that are scheduled to vest on February 21, 2020 and (ii) 5,127 restricted stock units, that are scheduled to vest on March 1, 2020. Excludes (i) 5,127 restricted stock units, that are scheduled to vest on March 1, 2021, (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 are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021, and (iv) 13,183 performance-based restricted stock units awarded to Mr. Van’t Hof on March 1, 2019, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021 and are scheduled to vest in five equal annual installments beginning on March 1, 2025.

(4)

Includes (i) 1,866 restricted stock units, that are scheduled to vest on February 21, 2020 and (ii) 2,930 restricted stock units, that are scheduled to vest on March 1, 2020. Excludes 2,930 restricted stock units, that are scheduled to vest on March 1, 2021. Also excludes (i) 11,700 performance-based restricted stock units awarded to Ms. Dick on February 16, 2017, that will vest effective December 31, 2019 (representing 200% vesting of the originally reported amount) subject to 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, 2019 by Diamondback’s compensation committee, (ii) 8,396 performance-based restricted stock units awarded to Ms. Dick on February 13, 2018, which awards are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-

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year performance period ending December 31, 2020 and (iii) 13,183 performance-based restricted stock units awarded to Ms. Dick on March 1, 2019, which are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021.

(5)

Includes 2,344 restricted stock units, that are scheduled to vest on March 1, 2020. Excludes 2,344 restricted stock units, that are scheduled to vest on March 1, 2021. Also excludes 10,546 performance-based restricted stock units awarded to Mr. Zmigrosky on March 1, 2019, that are subject to the satisfaction of certain stockholder return performance conditions relative to Diamondback’s peer group during the three-year performance period ending on December 31, 2021.


(6)	Excludes 1,830 restricted stock units that are schedule to vest on the earlier of the one-year anniversary of the date of grant and the date of the 2020 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, 2020 by each unitholder known by us to beneficially own of 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	%
Capital World Investors.⁽³⁾ 333 South Hope Street Los Angeles, CA 90071	4,028,333	9.2	%	—	—
Clearbridge Investments, LLC ⁽⁴⁾ 620 8th Avenue New York, NY 10018	3,908,080	8.9	%	—	—
Tortoise Capital Advisors, L.L.C. ⁽⁵⁾ 5100 W. 115th Place Leawood, Kansas 66211	2,975,676	6.8	%	—	—
HITE Hedge Asset Management LLC ⁽⁶⁾ 300 Crown Colony Drive, Suite 108 Quincy, MA 02169	2,380,436	5.4	%	—	—


(1)	Beneficial ownership is determined in accordance with SEC rules. The percentage of common units beneficially owned is based on 43,700,000 common units outstanding as of January 31, 2020. Except as noted, each unitholder in the above table is believed to have sole voting and sole investment power with respect to the common units and Class B units beneficially held.

(2)

Diamondback Energy, Inc. is a publicly traded company and holds no common units and no Class B units directly. Diamondback has the beneficial ownership of 107,815,152 Class B units, which are held by Energen Resources Corporation, its indirect wholly owned subsidiary (“Energen Resources”). The 107,815,152 Class B units, together with the same number of units of the Operating Company (each, an “OpCo unit”), held by Energen Resources, are exchangeable from time to time, at Diamondback’s discretion, for common units (that is, one OpCo unit and one Class B unit, together, are exchangeable for one common unit), and, as a result, Diamondback may be deemed to have the beneficial ownership of such common units. Diamondback also has shared voting and dispositive power of 107,815,152 Class B units held by Energen Resources, which represent 100% of the outstanding Class B units. The directors of Diamondback are Travis D. Stice, Steven E. West, Michael P. Cross, David L. Houston, Mark L. Plaumann and Melanie M. Trent. Travis D. Stice is the sole director of Energen Resources.


(3)	Based solely on Schedule 13G filed with the SEC on February 14, 2020 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, 4,028,333 common units. No shared voting power and no shared dispositive power was reported by Capital World.

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(4)	Based solely on Schedule 13G filed with the SEC on February 14, 2020 by Clearbridge Investments, LLC (“Clearbridge”). Clearbridge reported beneficial ownership of, as well as sole voting power and sole dispositive power over, 3,908,080 common units. No shared voting power and no shared dispositive power was reported by Clearbridge.

(5)

Based solely on Schedule 13G/A filed with the SEC on February 14, 2020 by Tortoise Capital Advisors, L.L.C. (“TCA”). These common units are owned of record by clients of TCA who have the right to receive, or the power to direct the receipt of, dividends from, or the proceeds from the sale of, such securities. No such client is known to have such right or power with respect to more than 5% of this class of securities. TCA reported sole voting power and sole dispositive power over 76,201 common units, shared voting power over 2,598,996 common units, shared dispositive power over 2,899,475 common units and beneficial ownership of 2,975,676 common units.

(6)

Based solely on Schedule 13G jointly filed with the SEC on February 13, 2020 by HITE Hedge Asset Management LLC, James M. Jampel, HITE Hedge LP, HITE MLP LP, HITE Hedge QP LP, HITE MLP Advantage LP, HITE Energy LP, and HITE Hedge Offshore Ltd. HITE Hedge Asset Management LLC reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,380,436 common units. James M. Jampel reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 2,380,436 common units. HITE Hedge LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 392,254 common units. HITE MLP LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 198,096 common units. HITE Hedge QP LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 400,898 common units. HITE MLP Advantage LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 123,314 common units. HITE Energy LP reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 93,454 common units. HITE Hedge Offshore Ltd. reported beneficial ownership of, as well as shared voting power and shared dispositive power over, 1,172,420 common units. No sole voting power and no sole dispositive power was reported by any filer. HITE Hedge Asset Management LLC, for which Mr. Jampel is the managing member, is the investment advisor for HITE Hedge LP, HITE MLP LP, HITE Hedge QP LP, HITE MLP Advantage LP, HITE Energy LP, and HITE Hedge Offshore Ltd. Mr. Jampel disclaims beneficial ownership of any securities owned by the filers.

Securities Authorized For Issuance Under Equity Compensation Plans

The following table summarizes information about our equity compensation plans as of December 31, 2019:



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⁾	2,226,895	—	12,924,620


(1)	This information relates to our LTIP, which our general partner adopted at the closing of the IPO in May 2019. For a description of the LTIP, see “Item 11. Executive Compensation– Long-Term Incentive Plan.”

Change in Control

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, 2019 under the LTIP, in connection with certain termination events, including a termination related to a change of control of Viper or Diamondback.

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Under the terms of Mr. Stice’s employment agreement with Diamondback and the terms of the phantom unit awards made to Mr. Stice under the LTIP, all unvested phantom unit awards granted to Mr. Stice will accelerate and immediately vest upon (i) the change of control of Viper or Diamondback, provided that Diamondback is the sole general partner of Viper, (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, 2019, Mr. Stice held 114,286 unvested phantom units granted under the LTIP, all which are scheduled to vest in five equal installments beginning on May 28, 2020, and had a value of $2,033,130 as of December 31, 2019.

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 Viper or Diamondback, provided that Diamondback is the sole general partner or Viper, or upon such executive officer’s death or disability. As of December 31, 2019, Mr. Van’t Hof held 1,142,857 unvested phantom units granted under the LTIP, all of which are scheduled to vest in five equal installments beginning on May 28, 2020, and had a value of $20,331,390 as of December 31, 2019, Ms. Dick held 57,143 unvested phantom units granted under the LTIP, all of which are scheduled to vest in five equal installments beginning on May 28, 2020, and had a value of $1,016,610 as of December 31, 2019, and Mr. Zmigrosky held 22,857 unvested phantom units granted under the LTIP, all of which are scheduled to vest in five equal installments beginning on May 28, 2020, and had an aggregate value of $406,626 as of December 31, 2019.

No other executive officers of our general partner held equity awards under the LTIP as of December 31, 2019.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Payments to our General Partner and its Affiliates

Diamondback owns 107,815,152 Class B units, representing an aggregate 71% limited partner interest. In addition, our general partner owns a general partner interest in us.

At the closing of the IPO, our general partner and Energen Resources Corporation, a subsidiary of Energen, entered into the first amended and restated agreement of limited partnership of Rattler Midstream LP, dated May 28, 2019, or our partnership agreement. Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses incurred or paid on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The 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 general partner is entitled to determine the expenses that are allocable to us. For the year ended December 31, 2019, our general partner allocated $0.4 million of such expenses to us.

Diamondback is entitled to receive its pro rata portion of the distributions we make on our common units and the Operating Company makes in respect of the OpCo units. Holders of Class B units are not entitled to receive cash distributions except to the extent of the cash preferred distributions equal to 8% per annum payable quarterly on the $1.0 million capital contribution made to us by Diamondback in connection with the issuance of the Class B units in the recapitalization transaction. During the year ended December 31, 2019, Diamondback received distributions from us and the Operating Company in the aggregate amount of $0.02 million.

Agreements with our Affiliates in Connection with the IPO

We and other parties entered into the various agreements that affected the transactions contemplated by our IPO, including the vesting of assets in, and the assumption of liabilities by, us and our subsidiaries, and the application of the proceeds from our IPO. While not the result of arm’s-length negotiations, we believe the terms of all of our initial agreements with Diamondback and its affiliates are, and specifically intend the rates to be, generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. All of the transaction expenses incurred in connection with these transactions, including the expenses associated with transferring assets into our subsidiaries, were paid for with the proceeds from our IPO.

Asset Contribution Agreement

In July 2018, we entered into a contribution agreement with Diamondback by which Diamondback contributed a substantial portion of our assets to us, including (i) the Rattler assets, (ii) Diamondback’s field office, certain produced water disposal wells, gathering and frac ponds in Reeves County, Texas, or the Luxe assets, (iii) the Brigham assets, (iv) the sourced

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water assets, (v) certain of Diamondback’s real property interests in Glasscock, Howard, Martin, Midland, Pecos and Reeves Counties, Texas, or the land assets, (vi) the Tall Towers interest, and (vii) 25% membership interests in HMW LLC that Diamondback had acquired in October 2014, or the HMW Interest.

The contribution of the Rattler assets occurred during fiscal years 2016 and 2017 and was comprised of $208.6 million of net property, plant and equipment, $7.9 million in equity method investments and $0.4 million of asset retirement obligations related to the contributed assets. The contribution of the Luxe assets was effective as of September 1, 2016, and the contribution of the land assets was effective as of January 1, 2017. The contribution of the Brigham assets was effective as of February 28, 2017 and had an estimated fair market value at the time of transfer of $46.7 million. The contribution of the sourced water assets was effective as of January 1, 2018 and had a carrying value at the time of transfer of $32.8 million and $6.0 million of that amount related to sourced water inventory.

The contribution of the Tall Towers interest was effective as of January 31, 2018.

HMW LLC was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to E&P companies operating in Midland, Martin and Andrews Counties, Texas. The contribution of the HMW Interest was effective as of January 1, 2016. We recorded $1.4 million in income from investments associated with our interests in HMW LLC during fiscal year 2017. On June 30, 2018, HMW LLC’s operating agreement was amended, effective as of January 1, 2018. In exchange for our 25% investment, we received a 50% undivided ownership interest in two of the four produced water disposal wells and associated assets previously owned by HMW LLC. Our basis in the assets was equivalent to our basis in the equity method investment in HMW LLC.

In February 2019, we entered into a contribution agreement with Diamondback by which Diamondback contributed midstream assets to us, including certain crude oil gathering, produced water disposal wells, land and buildings Diamondback had acquired pursuant to the Ajax acquisition on October 31, 2018 and the Energen acquisition on November 29, 2018. The contribution was effective as of January 1, 2019 and was comprised of approximately $297.6 million of net property, plant and equipment and $3.3 million of asset retirement obligations related to the contributed assets.

Services and Secondment Agreement

We and our general partner also entered into the services and secondment agreement with Diamondback setting forth the operational services arrangements described below. 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. For the year ended December 31, 2019, we paid $5.1 million under the terms of the services and secondment agreement.

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.

Commercial Agreements

We derive substantially all of our revenue from our commercial agreements with Diamondback for the provision of midstream services. For the year ended December 31, 2019, we received $9.9 million, $14.3 million, $271.6 million and $112.7 million under the terms of our crude oil gathering agreement, our gas gathering and compression agreement, our produced and

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flowback water gathering and disposal agreement and our sourced water services agreement with Diamondback, respectively. For the year ended December 31, 2018, we received $16.0 million, $6.4 million, $72.4 million and $77.0 million under the terms of our crude oil gathering agreement, our gas gathering and compression agreement, our produced and flowback water gathering and disposal agreement and our sourced water services agreement with Diamondback, respectively. For the year ended December 31, 2017, we received $7.6 million, $2.9 million and $27.9 million under the terms of our crude oil gathering agreement, our gas gathering and compression agreement and our produced and flowback water gathering and disposal agreement with Diamondback, respectively. We did not provide water services to Diamondback in 2017.

Exchange Agreement

We entered into an exchange agreement with Diamondback, our general partner and OpCo, under which Diamondback can tender OpCo units and an equal number of Diamondback’s Class B units, together referred to as the tendered units, for redemption to OpCo and us. As consideration for the tendered units, Diamondback has the right to receive upon redemption, at the election of OpCo with the approval of the conflicts committee of our general partner’s board of directors, either the number of our common units equal to the number of tendered units or a cash payment equal to the sum of (i) the number of tendered units multiplied by the average daily trading price of our common units for the prior 20 days plus (ii) the number of tendered units multiplied by the quotient of $1 million divided by the number of then outstanding Class B units. In addition, we have the right but not the obligation, to directly purchase such tendered units for, subject to the approval of the conflicts committee of our general partner’s board of directors, cash or our common units at our election.

The exchange agreement also provides that, subject to certain exceptions, Diamondback does not have the right to exchange its Rattler OpCo units if OpCo or if we determine that such exchange would be prohibited by law or regulation or would violate other agreements to which we may be subject, and OpCo and we may impose additional restrictions on the exchange that either of us determines necessary or advisable so that we are not treated as a “publicly traded partnership” for U.S. federal income tax purposes.

If OpCo elects to receive our common units in exchange for Diamondback’s tendered units, the exchange will be on a one-for-one basis, subject to adjustment in the event of splits or combinations of units, distributions of warrants or other unit purchase rights, specified extraordinary distributions and similar events. If OpCo elects to deliver cash in exchange for Diamondback’s tendered units, or if we exercise our right to purchase tendered units for cash, the amount of cash payable will be based on the average daily trading price of our common units for the prior 20 days.

Registration Rights Agreement

We entered into a registration rights agreement with Diamondback under which Diamondback is entitled to demand registration rights, including the right to demand that a shelf registration statement be filed, and “piggyback” registration rights, for common units that it owns or acquires, including through the exchange of Diamondback’s Class B units and our common units for OpCo units in accordance with the exchange agreement.

Equity Contribution Agreement

Prior to our IPO, we entered into an equity contribution agreement with the Operating Company under which we contributed all of the net proceeds of our IPO to the Operating Company in exchange for 38,000,000 Operating Company units. The Operating Company used the contributed funds to make distributions to Diamondback and for general company purposes.

Fasken Center Agreements

We have entered into a long-term lease agreement with Diamondback for certain office space located within the Fasken Center. Effective as of January 31, 2018, Diamondback contributed all of its membership interest in Tall Towers, which owns the Fasken Center in Midland, Texas, to OpCo pursuant to the asset contribution agreement. Diamondback is a tenant in the Fasken Center. For the year ended December 31, 2019, we received $5.2 million related to our lease agreement with Diamondback.

Tax Sharing Agreement

At the closing of our IPO, OpCo entered into a tax sharing agreement with Diamondback, dated May 28, 2019, pursuant to which OpCo agreed to reimburse Diamondback for our share of state and local income and other taxes for which OpCo’s results are included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax that OpCo 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

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which OpCo may be a member for this purpose, to owe less or no tax. In such a situation, OpCo agreed to nevertheless reimburse Diamondback for the tax OpCo would have owed had the attributes not been available or used for its benefit, even though Diamondback had no cash tax expense for that period. For the year ended December 31, 2019, we accrued state income tax expense of $0.2 million for our share of Texas margin tax for which our results are included in a combined tax return filed by Diamondback.

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 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 West, Laurie Argo and Arturo Vivar serve as the independent members of the board of directors of our general partner.

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, 2019 and 2018. 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, 2019 and 2018 were approved by the audit committee.

The following table summarizes the aggregate Grant Thornton LLP fees that were allocated to us for independent auditing, tax and related services:



	Year Ended December 31,
	2019		2018
	(In thousands)
Audit fees⁽¹⁾	$	442	$	494
Audit-related fees⁽²⁾	—		—
Tax fees⁽³⁾	—		—
All other fees⁽⁴⁾	—		—
Total	$	442	$	494


(1)	Audit 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.

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(2)	Audit-related 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.


(3)	Tax fees represent amounts billed in each of the years presented for professional services rendered in connection with tax compliance, tax advice, and tax planning.


(4)	All other fees represent amounts billed in each of the years presented for services not classifiable under the other categories listed in the table above.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES



(a)	Documents included in this report:
	1. Financial Statements
	Report of Independent Registered Public Accounting Firm	F-1
	Consolidated Balance Sheets	F-2
	Consolidated Statements of Operations	F-4
	Consolidated Statements of Comprehensive Income	F-5
	Consolidated Statements of Changes in Unitholders’ Equity	F-6
	Consolidated Statements of Cash Flows	F-10
	Notes to Consolidated Financial Statements	F-12

	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#		Amended and Restated Contribution Agreement among Diamondback Energy, Inc., Diamondback E&P LLC, Diamondback O&G LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), dated as of July 31, 2018 (incorporated by reference to Exhibit 2.1 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
2.2#		Contribution Agreement among Diamondback Energy, Inc., Diamondback E&P LLC, Energen Resources Corporation, Rattler Midstream Operating LLC and Tall City Towers LLC, effective as of January 1, 2019 (incorporated by reference to Exhibit 2.2 of Amendment No. 3 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on February 20, 2019).
3.1		Certificate of Limited Partnership of Rattler Midstream LP (formerly Rattler Midstream Partners LP)(incorporated by reference to Exhibit 3.1 of the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on August 7, 2018).
3.2		Certificate of Amendment to the Certificate of Limited Partnership of Rattler Midstream LP (formerly Rattler Midstream Partners LP)(incorporated by reference to Exhibit 3.2 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
3.3		First Amended and Restated Agreement of Limited Partnership of Rattler Midstream LP, dated May 28, 2019 (incorporated by reference to Exhibit 3.1 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
3.4		Certificate of Formation of Rattler Midstream Operating LLC (formerly White Fang Energy LLC) (incorporated by reference to Exhibit 3.3 of the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on August 7, 2018).
3.5		Certificate of Amendment to the Certificate of Formation of Rattler Midstream Operating LLC (formerly White Fang Energy LLC) (incorporated by reference to Exhibit 3.4 of the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on August 7, 2018).
3.6		Certificate of Amendment to the Certificate of Formation of Rattler Midstream Operating LLC (formerly Rattler Midstream LLC) (incorporated by reference to Exhibit 3.6 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
3.7		Second Amended and Restated Limited Liability Company Agreement of Rattler Midstream Operating LLC (incorporated by reference to Exhibit 3.2 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
3.8		Certificate of Formation of Rattler Midstream GP LLC (incorporated by reference to Exhibit 3.6 of the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on August 7, 2018).
3.9		First Amended and Restated Limited Liability Company Agreement of Rattler Midstream GP LLC (incorporated by reference to Exhibit 3.3 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
4.1*		Description of Securities of the Registrant.

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3. Exhibits
Exhibit Number		Description
4.2		Registration Rights Agreement, dated May 28, 2019, by and between Rattler Midstream LP and Energen Resources Corporation (incorporated by reference to Exhibit 4.1 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.1		Lease Agreement, dated as of April 19, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.7 to Amendment No. 2 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on June 11, 2012).
10.2		Lease Amendment No. 1 to Lease Agreement, dated as of June 6, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.8 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on May 8, 2012).
10.3		Lease Amendment No. 2 to Lease Agreement, dated as of August 5, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.9 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on May 8, 2012).
10.4		Lease Amendment No. 3 to Lease Agreement, dated as of September 28, 2011, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.10 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on May 8, 2012).
10.5		Lease Amendment No. 4 to Lease Agreement, dated February 6, 2012, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.11 to Amendment No. 1 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on May 8, 2012).
10.6		Lease Amendment No. 5 to Lease Agreement, dated as of July 25, 2012, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 to Amendment No. 5 to the Registration Statement on Form S-1 (File No. 333-179502) filed by Diamondback Energy, Inc. with the SEC on October 2, 2012).
10.7		Lease Amendment No. 6 effective May 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Windsor Permian LLC (incorporated by reference to Exhibit 10.39 to the Form 10-K/A (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on April 10, 2013).
10.8		Lease Amendment No. 7 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on August 8, 2013).
10.9		Lease Amendment No. 8 effective September 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on August 8, 2013).
10.10		Lease Amendment No. 9 effective August 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2013).
10.11		Lease Amendment No. 10 effective October 1, 2013 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2013).
10.12		Lease Amendment No. 11 effective July 31, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.1 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.13		Lease Amendment No. 12 effective October 23, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.2 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.14		Lease Amendment No. 13 effective October 30, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.3 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.15		Lease Amendment No. 14 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.4 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).

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3. Exhibits
Exhibit Number		Description
10.16		Lease Amendment No. 15 effective November 10, 2014 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.5 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.17		Lease Amendment No. 16 effective April 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.6 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.18		Lease Amendment No. 17 effective April 1, 2015 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.7 to the Form 10-Q (File No. 001-35700) filed by Diamondback Energy, Inc. with the SEC on November 5, 2015).
10.19		Lease Amendment No. 18 effective January 16, 2017 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.33 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.20		Lease Amendment No. 19 effective January 16, 2017 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.34 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.21		Lease Amendment No. 20 effective January 16, 2017 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.35 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.22		Lease Amendment No. 21 effective October 4, 2017 to Lease Agreement dated as of April 19, 2011, as amended, by and between Fasken Midland, LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.36 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.23		Lease Amendment No. 22 effective March 6, 2018 to Lease Agreement dated as of April 19, 2011, as amended, by and between Tall City Towers LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.37 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.24		Lease Amendment No. 23 effective September 1, 2018 to Lease Agreement dated as of April 19, 2011, as amended, by and between Tall City Towers LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.38 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.25		Lease Amendment No. 24 effective September 1, 2018 to Lease Agreement dated as of April 19, 2011, as amended, by and between Tall City Towers LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.39 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.26		Lease Amendment No. 25 effective September 20, 2018 to Lease Agreement dated as of April 19, 2011, as amended, by and between Tall City Towers LLC and Diamondback E&P LLC (incorporated by reference to Exhibit 10.40 of Amendment No. 2 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on January 22, 2019).
10.27^		Gas Gathering and Compression Agreement by and between Diamondback E&P LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), effective as of January 1, 2018 (incorporated by reference to Exhibit 10.4 of Amendment No. 6 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on May 6, 2019).
10.28^		Amended and Restated Crude Oil Gathering Agreement by and between Diamondback E&P LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), effective as of January 1, 2018 (incorporated by reference to Exhibit 10.6 of Amendment No. 6 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on May 6, 2019).
10.29^		Amended and Restated Produced and Flowback Water Gathering and Disposal Agreement by and between Diamondback E&P LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), effective as of January 1, 2018 (incorporated by reference to Exhibit 10.7 of Amendment No. 6 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on May 6, 2019).

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3. Exhibits
Exhibit Number		Description
10.30^		Freshwater Purchase and Services Agreement by and between Diamondback E&P LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), effective as of January 1, 2018 (incorporated by reference to Exhibit 10.8 of Amendment No. 6 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on May 6, 2019).
10.31		First Amendment to Gas Gathering and Compression Agreement by and between Diamondback E&P LLC and Rattler Midstream Operating LLC (formerly Rattler Midstream LLC), effective as of September 5, 2018 (incorporated by reference to Exhibit 10.5 of Amendment No. 3 to the Registrant’s Registration Statement on Form S-1 (File No. 333-226645) filed on February 20, 2019).
10.32		Exchange Agreement, dated as of May 28, 2019, by and among Rattler Midstream LP, Rattler Midstream GP LLC, Rattler Midstream Operating LLC and Energen Resources Corporation (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.33		Credit Agreement, dated May 28, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.2 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.34+		Rattler Midstream LP Long-Term Incentive Plan, adopted effective as of May 22, 2019, (incorporated by reference to Exhibit 10.3 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.35+		Form of Indemnification Agreement (incorporated by reference to Exhibit 10.4 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.36		Equity Contribution Agreement, dated as of May 28, 2019, by and between Rattler Midstream LP and Rattler Midstream Operating LLC (incorporated by reference to Exhibit 10.5 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.37		Services and Secondment Agreement, dated as of May 28, 2019, by and among Diamondback Energy, Inc., Diamondback E&P LLC, Rattler Midstream GP LLC, Rattler Midstream LP, and Rattler Midstream Operating LLC (incorporated by reference to Exhibit 10.6 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.38		Tax Sharing Agreement, dated as of May 28, 2019, by and between Diamondback Energy, Inc. and Rattler Midstream Operating LLC (incorporated by reference to Exhibit 10.7 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.39+		Form of Phantom Unit Agreement (incorporated by reference to Exhibit 10.8 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019).
10.40		First Amendment to the Credit Agreement and Guaranty and Security Agreement, dated as of October 23, 2019, by and among Rattler Midstream Operating LLC, as borrower, Rattler Midstream LP, as parent, Wells Fargo Bank, National Association, as the administrative agent, and certain lenders from time to time party thereto (incorporated by reference to Exhibit 10.1 of the Registrant’s Current Report on Form 8-K (File 001-38919) filed on October 28, 2019).
10.41*+		Form of Phantom Unit Agreement.
21.1*		List of Subsidiaries of the Registrant.
23.1*		Consent of Grant Thornton LLP.
31.1*		Certification of Chief Executive Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
31.2*		Certification of Chief Financial Officer of the Registrant pursuant to Rule 13a-14(a) promulgated under the Securities Exchange Act of 1934, as amended.
32.1++		Certification of Chief Executive Officer and Chief Financial Officer of the Registrant pursuant to Rule 13a-14(b) promulgated under the Securities Exchange Act of 1934, as amended, and Section 1350 of Chapter 63 of Title 18 of the United States Code.
101		The following financial information from the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2019, 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).

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*	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.

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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 25, 2020
		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 25, 2020
Travis D. Stice	(Principal Executive Officer)

/s/ Teresa L. Dick	Chief Financial Officer	February 25, 2020
Teresa L. Dick	(Principal Financial and Accounting Officer)

/s/ Kaes Van’t Hof	President and Director	February 25, 2020
Kaes Van’t Hof

/s/ Laurie H. Argo	Director	February 25, 2020
Laurie H. Argo

/s/ Arturo Vivar	Director	February 25, 2020
Arturo Vivar

/s/ Steven E. West	Director	February 25, 2020
Steven E. West

S-1

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Board of Directors and Shareholders

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, 2019 and 2018, the related consolidated statements of operations, statements of comprehensive income, statement of changes in unitholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

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 supporting 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 25, 2020

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Rattler Midstream LP

Consolidated Balance Sheets



	December 31,			December 31,
	2019			2018*
	(In thousands)
Assets
Current assets:
Cash	$	10,633		$	8,564
Accounts receivable—related party	50,270			18,274
Accounts receivable—third party	9,071			1,849
Sourced water inventory	14,325			9,200
Other current assets	1,428			4,209
Total current assets	85,727			42,096
Property, plant and equipment:
Land	88,509			70,373
Property, plant and equipment	930,768			415,888
Accumulated depreciation, amortization and accretion	(61,132		)	(28,317		)
Property, plant and equipment, net	958,145			457,944
Right of use assets	418			—
Equity method investments	479,558			—
Real estate assets, net	98,679			93,023
Intangible lease assets, net	8,070			10,954
Other assets	5,796			—
Total assets	$	1,636,393		$	604,017

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Balance Sheets - Continued



	December 31,			December 31,
	2019			2018*
	(In thousands, except unit amounts)
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable	$	147		$	100
Accrued liabilities	76,625			51,804
Taxes payable	189			11,514
Short-term lease liability	418			—
Total current liabilities	77,379			63,418
Long-term debt	424,000			—
Asset retirement obligations	11,347			561
Deferred income taxes	7,827			12,912
Total liabilities	520,553			76,891
Commitments and contingencies (Note 17)
Unitholders' equity:
Limited partners member's equity—Diamondback	—			527,125
General partner—Diamondback	979			—
Common units—public (43,700,000 units issued and outstanding as of December 31, 2019)	737,777			—
Class B units—Diamondback (107,815,152 units issued and outstanding as of December 31, 2019)	979			1
Accumulated other comprehensive loss	(198		)	—
Total Rattler Midstream LP unitholders’ equity	739,537			527,126
Non-controlling interest	376,928			—
Non-controlling interest in accumulated other comprehensive loss	(625		)	—
Total equity	1,115,840			527,126
Total liabilities and unitholders’ equity	$	1,636,393		$	604,017

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Statements of Operations



	Year Ended December 31,
	2019			2018*		2017*
				Predecessor		Predecessor
	(In thousands, expect per unit amounts)
Revenues:
Revenues—related party	$	409,120		$	169,396	$	38,414
Revenues—third party	24,324			3,292		881
Rental income—related party	4,771			2,383		—
Rental income—third party	7,890			8,125		—
Other real estate income—related party	379			228		—
Other real estate income—third party	1,189			1,043		—
Total revenues	447,673			184,467		39,295
Costs and expenses:
Direct operating expenses	106,311			33,714		10,557
Cost of goods sold (exclusive of depreciation and amortization)	62,856			38,852		—
Real estate operating expenses	2,643			1,872		—
Depreciation, amortization and accretion	42,336			25,134		3,486
General and administrative expenses	12,663			1,999		1,265
Loss on disposal of property, plant and equipment	1,524			2,577		—
Total costs and expenses	228,333			104,148		15,308
Income from operations	219,340			80,319		23,987
Other income (expense):
Interest expense, net	(1,039		)	—		—
Income (loss) from equity method investments	(6,329		)	—		1,366
Total other income (expense), net	(7,368		)	—		1,366
Net income before income taxes	211,972			80,319		25,353
Provision for income taxes	26,253			17,359		4,688
Net income after taxes	$	185,719		$	62,960	$	20,665

Net income before initial public offering	$	65,995

Net income subsequent to initial public offering	$	119,724
Net income attributable to non-controlling interest subsequent to initial public offering	90,922
Net income attributable to Rattler Midstream LP	$	28,802

Net income attributable to limited partners per common unit - subsequent to initial public offering:
Basic	$	0.64
Diluted	$	0.64
Weighted average number of limited partner common units outstanding:
Basic	43,622
Diluted	43,622

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Statements of Comprehensive Income



	Year Ended December 31,
	2019			2018*		2017*
				Predecessor		Predecessor
	(In thousands)
Net Income	$	185,719		$	62,960	$	20,665
Other comprehensive income:
Change in accumulated other comprehensive loss of equity method investees attributable to non-controlling interest	(625		)	—		—
Change in accumulated other comprehensive loss of equity method investees attributable to limited partner	(198		)	—		—
Total other comprehensive income	(823		)	—		—
Comprehensive income	$	184,896		$	62,960	$	20,665

Comprehensive income before initial public offering	65,995
Comprehensive income attributable to non-controlling interest	90,297
Comprehensive income attributable to Rattler Midstream LP	$	28,604

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Statement of Changes in Unitholders’ Equity



	Predecessor			Partnership
	Limited Partners Member's Equity			Limited Partners						General Partner		Non-Controlling Interest
	Amount			Common Units	Amount		Class B Units	Amount		Amount		Amount		Total
	(In thousands)
Balance at December 31, 2018*	$	527,125		—	$	—	—	$	1	$	—	$	—	$	527,126
Contributions from Diamondback	458,674				—			—		—		—		458,674
Net income	39,356				—			—		—		—		39,356
Balance at March 31, 2019	1,025,155			—	—		—	1		—		—		1,025,156
Net income prior to the offering	26,639				—			—		—		—		26,639
Distributions prior to the offering	(33,712		)		—			—		—		—		(33,712		)
Balance at May 28, 2019	1,018,082			—	—		—	1		—		—		1,018,083
Net proceeds from the offering - public	—			43,700	719,627			—		—		—		719,627
Net proceeds from the offering - General Partner	—				—			—		1,000		—		1,000
Net proceeds from the offering - Diamondback	—				—		107,815	999		—		—		999
Unit-based compensation	—				831			—		—		—		831
Elimination of current and deferred tax liabilities	31,094				—			—		—		—		31,094
Allocation of net investment to unitholder	(322,663		)		—			—		—		322,663		—
Distributions to Diamondback (Note 1)	(726,513		)		—			—		—		—		(726,513		)
Net income subsequent to the offering	—				4,803			—		—		15,237		20,040
Balance at June 30, 2019	$	—		43,700	$	725,261	107,815	$	1,000	$	1,000	$	337,900	$	1,065,161

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Statement of Changes in Unitholders’ Equity - Continued



	Partnership
	Limited Partners								General Partner			Non-Controlling Interest			Accumulated Other Comprehensive Income			Non-Controlling Interest-Accumulated Other Comprehensive Income
	Common Units	Amount			Class B Units	Amount			Amount			Amount			Amount			Amount			Total
	(In thousands)
Balance at June 30, 2019	43,700	$	725,261		107,815	$	1,000		$	1,000		$	337,900		$	—		$	—		$	1,065,161
Net proceeds from the offering - public		(251		)		—			—			—			—			—			(251		)
Unit-based compensation		2,158				—			—			—			—			—			2,158
Net income		11,531				—			—			36,549			—			—			48,080
Balance at September 30, 2019	43,700	738,699			107,815	1,000			1,000			374,449			—			—			1,115,148
Unit-based compensation, net of distribution equivalent right payments		1,468				—			—			—			—			—			1,468
Distributions to public		(14,858		)		—			—			—			—			—			(14,858		)
Distributions to Diamondback (Note 1)		—				(21		)	—			—			—			—			(21		)
Distributions to General Partner		—				—			(21		)	—			—			—			(21		)
Distributions to non-controlling interest		—				—			—			(36,657		)	—			—			(36,657		)
Other comprehensive income		—				—			—			—			(198		)	(625		)	(823		)
Net income		12,468				—			—			39,136			—			—			51,604
Balance at December 31, 2019	43,700	$	737,777		107,815	$	979		$	979		$	376,928		$	(198	)	$	(625	)	$	1,115,840

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Consolidated Statement of Changes in Unitholders’ Equity - Continued



	Predecessor			Partnership
	Limited Partners Member's Equity			Limited Partners						General Partner		Non-Controlling Interest
	Amount			Common Units	Amount		Class B Units	Amount		Amount		Amount		Total
	(In thousands)
Balance at December 31, 2017*	$	292,608		—	$	—	—	$	—	$	—	$	—	$	292,608
Contributions from Diamondback	175,100				—			—		—		—		175,100
Net income	14,396				—			—		—		—		14,396
Balance at March 31, 2018*	482,104			—	—		—	—		—		—		482,104
Contributions from Diamondback	3,417				—			—		—		—		3,417
Net income	15,472				—			—		—		—		15,472
Balance at June 30, 2018*	500,993			—	—		—	—		—		—		500,993
Contributions from Diamondback	(1,982		)		—			—		—		—		(1,982		)
Net income	17,780				—			—		—		—		17,780
Balance at September 30, 2018*	516,791			—	—		—	—		—		—		516,791
Contributions from Diamondback	(4,978		)		—			1		—		—		(4,977		)
Net income	15,312				—			—		—		—		15,312
Balance at December 31, 2018*	$	527,125		—	$	—	—	$	1	$	—	$	—	$	527,126

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

*See Note 1 for information regarding the basis of financial statement presentation

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Rattler Midstream LP

Consolidated Statement of Changes in Unitholders’ Equity - Continued



	Predecessor			Partnership
	Limited Partners Member's Equity			Limited Partners						General Partner		Non-Controlling Interest
	Amount			Common Units	Amount		Class B Units	Amount		Amount		Amount		Total
	(In thousands)
Balance at December 31, 2016*	$	92,729			$	—		$	—	$	—	$	—	$	92,729
Contributions from Diamondback	58,742				—			—		—		—		58,742
Net income	2,938				—			—		—		—		2,938
Balance at March 31, 2017*	154,409			—	—		—	—		—		—		154,409
Contributions from Diamondback	(3,679		)		—			—		—		—		(3,679		)
Net income	5,146				—			—		—		—		5,146
Balance at June 30, 2017*	155,876			—	—		—	—		—		—		155,876
Contributions from Diamondback	70,116				—			—		—		—		70,116
Net income	3,185				—			—		—		—		3,185
Balance at September 30, 2017*	229,177			—	—		—	—		—		—		229,177
Contributions from Diamondback	54,035				—			—		—		—		54,035
Net income	9,396				—			—		—		—		9,396
Balance at December 31, 2017*	$	292,608		—	$	—	—	$	—	$	—	$	—	$	292,608

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

*See Note 1 for information regarding the basis of financial statement presentation

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Consolidated Statements of Cash Flows



	Year Ended December 31,
	2019			2018*			2017*
				Predecessor			Predecessor
	(In thousands)
Cash flows from operating activities:
Net income	$	185,719		$	62,960		$	20,665
Adjustments to reconcile net income to net cash provided by operating activities:
Provision for deferred income taxes	26,253			5,845			4,471
Depreciation, amortization and accretion	42,336			25,134			3,486
Loss on disposal of property, plant and equipment	1,524			2,577			—
Unit-based compensation expense	5,208			—			—
Loss (Income) from equity method investments	6,329			—			(1,366		)
Changes in operating assets and liabilities:
Accounts receivable—related party	(65,032		)	17,625			(29,108		)
Accounts receivable—third party	(1,212		)	(1,849		)	—
Accounts payable, accrued liabilities and taxes payable	34,299			61,139			2,143
Other	(17,231		)	—			(283		)
Net cash provided by operating activities	218,193			173,431			8
Cash flows from investing activities:
Additions to property, plant and equipment	(241,786		)	(164,876		)	—
Contributions to equity method investments	(336,601		)	—			—
Proceeds from the sale of fixed assets	18			—			—
Net cash used in investing activities	(578,369		)	(164,876		)	—
Cash flows from financing activities:
Proceeds from borrowings from credit facility	463,000			—			—
Payments on credit facility	(39,000		)	—			—
Distribution equivalent rights	(751		)	—			—
Debt issuance costs	(4,310		)	—			—
Net proceeds from initial public offering—public	719,377			—			—
Net proceeds from initial public offering—General Partner	1,000			—			—
Net proceeds from initial public offering—Diamondback	999			1			—
Distribution to General Partner (Note 1)	(21		)	—			—
Distribution to public (Note 1)	(14,858		)	—			—
Distribution to Diamondback (Note 1)	(763,191		)	—			—
Net cash provided by financing activities	362,245			1			—
Net increase in cash	2,069			8,556			8
Cash at beginning of period	8,564			8			—
Cash at end of period	$	10,633		$	8,564		$	8
Supplemental disclosure of cash flow information:
Interest paid	$	2,707		$	—		$	—
Supplemental disclosure of non-cash financing activity:
Contributions from Diamondback	$	456,055		$	171,557		$	179,214

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Rattler Midstream LP

Consolidated Statements of Cash Flows - Continued



	Year Ended December 31,
	2019		2018*		2017*
			Predecessor		Predecessor
	(In thousands)

Supplemental disclosure of non-cash investing activity:
Increase in long term assets and inventory due to contributions from Diamondback	$	456,055	$	171,557	$	179,214
Change in accrued liabilities related to property, plant and equipment	$	4,176	$	2,693	$	—

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

*See Note 1 for information regarding the basis of financial statement presentation.

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Rattler Midstream LP

Notes to Consolidated Financial Statements

1. ORGANIZATION AND BASIS OF PRESENTATION

Organization

Rattler Midstream LP (the “Partnership”) is a publicly traded Delaware limited partnership, the common units of which are listed on the Nasdaq Global Select Market under the symbol “RTLR”. The Partnership was formed on July 27, 2018 by Diamondback Energy, Inc. (“Diamondback”) to, among other things, own, operate, develop and acquire midstream infrastructure assets in the Midland and Delaware Basins of the Permian Basin. Unless the context requires otherwise, references to “the Partnership” are intended to mean the business and operations of the Partnership and its consolidated subsidiary, Rattler Midstream Partners LLC (the “Operating Company” and, prior to May 28, 2019 for accounting purposes, the “Predecessor”).

On January 31, 2018, Diamondback, through its wholly owned subsidiary Tall City Towers LLC (“Tall Towers”), acquired from Fasken Midland LLC (“Fasken Midland”) certain real property and related assets in Midland, Texas (the “Fasken Center”). Tall Towers was contributed to the Predecessor effective January 31, 2018, see Note 4—Acquisitions.

The Predecessor’s assets, contributed from Diamondback, included (i) crude oil and natural gas gathering and transportation systems, (ii) produced water gathering and disposal systems and (iii) water sourcing and distribution systems. All of the Partnership’s businesses are located or operate in the Permian Basin in West Texas.

On August 7, 2018, a Registration Statement on Form S-1 (File No. 333-226645) was filed with the SEC relating to the proposed underwritten initial public offering (the “IPO”) of common units of the Partnership. Prior to the completion of the IPO, the Predecessor was a wholly owned subsidiary of Diamondback.

Prior to the closing on May 28, 2019 of the Partnership’s IPO of 38,000,000 common units representing limited partner interests, Diamondback owned all of the general and limited partner interests in the Partnership. On May 30, 2019, the underwriters purchased an additional 5,700,000 common units following the exercise in full of their over-allotment option on the same terms, at a price to the public of $17.50 per common unit. The Partnership received net proceeds of approximately $719.4 million from the sale of these common units after deducting offering expenses and underwriting discounts and commissions.

At the closing of the IPO, the Partnership (i) issued 107,815,152 Class B units representing an aggregate 71% voting limited partner interest in the Partnership in exchange for a $1.0 million cash contribution from Diamondback, (ii) issued a general partner interest in the Partnership to Rattler Midstream GP LLC (the “General Partner”) in exchange for a $1.0 million cash contribution from the General Partner, and (iii) caused the Operating Company to make a distribution of approximately $726.5 million to Diamondback. Diamondback, as the holder of the Class B units, and the General Partner, as the holder of the general partner interest, are entitled to receive cash preferred distributions equal to 8% per annum on the outstanding amount of their respective $1.0 million capital contributions, payable quarterly.

As of December 31, 2019, the General Partner held a 100% general partner interest in the Partnership. Diamondback owns all of the Partnership’s 107,815,152 Class B units that provide a 71% voting interest. Diamondback owns and controls the General Partner.

As of December 31, 2019, the Partnership owned a 29% controlling membership interest in the Operating Company and Diamondback owned, through its ownership of the Operating Company units, a 71% economic, non-voting interest in the Operating Company. However, as required by GAAP, the Partnership consolidates 100% of the assets and operations of the Operating Company in its financial statements and reflects a non-controlling interest.

Basis of Presentation

Prior to May 28, 2019, the Partnership’s services were performed by the Predecessor. The consolidated financial statements include the results of the Predecessor for the periods presented prior to the closing of the IPO on May 28, 2019. The Predecessor financial statements have been prepared from the separate records maintained by the Partnership and may not necessarily be indicative of the actual results of operations that might have occurred if the Predecessor had been operated separately during the periods reported.

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Notes to Consolidated Financial Statements - (Continued)

The consolidated results of operations following the completion of the IPO are presented together with the results of operations pertaining to the Predecessor. The assets of the Predecessor consist of produced water disposal wells and related gathering systems, office buildings, surface land and an oil gathering system and asset retirement obligations related to these assets, which were contributed effective January 1, 2019. See Note 4—Acquisitions. The capital contribution of the net proceeds from the IPO to the Operating Company in exchange for 29% of the limited liability company units of the Operating Company was accounted for as a combination of entities under common control, with assets and liabilities transferred at their carrying amounts in a manner similar to a pooling of interests. The Partnership did not own any assets prior to May 28, 2019, the date of the equity contribution agreement by and between the Partnership and the Predecessor. Prior to the IPO, the Predecessor was a wholly owned subsidiary of Diamondback. For periods prior to May 28, 2019, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in members’ equity of the Predecessor and, for periods on and after May 28, 2019, the accompanying consolidated financial statements and related notes thereto represent the financial position, results of operations, cash flows and changes in partners’ equity of the Partnership and its partially owned subsidiary.

The consolidated financial statements include the accounts of the Partnership and its subsidiaries after all significant intercompany balances and transactions have been eliminated upon consolidation.

Prior to 2018, the Partnership’s operations comprised a single operating business segment; however, with the contribution of Tall Towers, the Partnership’s operations are now reported in two operating business segments: (i) midstream services and (ii) real estate operations. See Note 19—Report of Operating Business Segments.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Certain amounts included in or affecting the Partnership’s financial statements and related notes must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities at the date of the financial statements.

The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s 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, but are not limited to, (i) revenue accruals, (ii) the fair value of long-lived assets and (iii) asset retirement obligations (“ARO”).

Cash

Cash represents unrestricted cash maintained in bank deposit accounts.

Accounts Receivable-Related Party

Accounts receivable-related party consist of receivables from Diamondback, or one of its affiliates. The receivable balance represents operating income less certain cash payments as of December 31, 2019 and 2018. The Partnership provides an allowance for doubtful receivables equal to the estimated uncollectible amounts. No allowance was deemed necessary at December 31, 2019 and 2018, respectively.

Sourced Water Inventory

Sourced water inventory is stated at the lower of historical cost or net realizable value. Inventory costs are determined under the weighted-average method.

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Notes to Consolidated Financial Statements - (Continued)

Property, Plant and Equipment

Property, plant and equipment (“PP&E”) consist of land, gathering pipelines, facilities and related equipment, which are stated at the lower of historical cost less accumulated depreciation, amortization and accretion, or fair value, if impaired. The Partnership capitalizes construction-related direct labor and material costs. Maintenance and repair costs are expensed as incurred. PP&E assets are depreciated using the straight-line method over the useful lives of the assets ranging from ten to thirty years. Upon sale or retirement of depreciable property, the respective cost and related accumulated depreciation, amortization and accretion is eliminated from the balance sheet and the resulting gain or loss is recognized in the statement of operations.

Equity Method Investments

An investment in an investee over which the Partnership exercises significant influence but does not control is accounted for using the equity method. Under the equity method, the Partnership’s share of the investee’s earnings or loss is recognized in the statement of operations. The Partnership reviews its investments to determine if a loss in value which is other than a temporary decline has occurred. If such a loss has occurred, the Partnership recognizes an impairment provision. No impairments were recorded for the Partnership’s equity method investments for the years ended December 31, 2019 and 2018.

Real Estate Assets

Real estate assets are stated at cost, less accumulated depreciation and amortization. The Partnership considers the period of future benefit of each respective asset to determine the appropriate useful life and depreciation and amortization is calculated using the straight-line method over the assigned useful life.

Upon acquisition of real estate properties, the purchase price is allocated to tangible assets, consisting of land and building, and to identified intangible assets and liabilities, which may include the value of above market and below market leases and the value of in-place leases. The allocation of the purchase price is based upon the fair value of each component of the property. Although independent appraisals may be used to assist in the determination of fair value, in many cases these values will be based upon management’s assessment of each property, the selling prices of comparable properties and the discounted value of cash flows from the asset.

The fair values of above market and below market in-place leases will be recorded based on the present value (using an interest rate which reflects the risks associated with the leases acquired) of the difference between (i) the contractual amounts to be paid pursuant to the in-place leases and (ii) an estimate of fair market lease rates for the corresponding in-place leases measured over a period equal to the non-cancelable term of the lease including any bargain renewal periods. The above market and below market lease values will be capitalized as intangible lease assets or liabilities. Above market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases. Below market lease values will be amortized as an adjustment of rental income over the remaining term of the respective leases, including any bargain renewal periods. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of above market and below market in-place lease values relating to that lease would be recorded as an adjustment to rental income.

The fair values of in-place leases will include estimated direct costs associated with obtaining a new tenant, and opportunity costs associated with lost rentals which are avoided by acquiring an in-place lease. Direct costs associated with obtaining a new tenant may include commissions, tenant improvements, and other direct costs and are estimated, in part, by management’s consideration of current market costs to execute a similar lease. These direct costs will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. The value of opportunity costs will be calculated using the contractual amounts to be paid pursuant to the in-place leases over a market absorption period for a similar lease. These intangibles will be included in intangible lease assets on the balance sheet and will be amortized to expense over the remaining term of the respective leases. If a lease were to be terminated prior to its stated expiration, all unamortized amounts of in-place lease assets relating to that lease would be expensed.

Impairment of Long-Lived Assets

The Partnership reviews its long-lived assets whenever events or circumstances indicate the carrying amount of a long-lived asset may not be recoverable. An impairment loss is recognized only if the carrying amount of a long-lived asset is not recoverable from its estimated future undiscounted cash flows. An impairment loss is the difference between the carrying amount

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Notes to Consolidated Financial Statements - (Continued)

and fair value of the asset. The Partnership had no impairment losses for the years ended December 31, 2019, 2018, and 2017, respectively.

Fair Value of Financial Instruments

The Partnership’s financial instruments consist of cash, receivables, payables and a revolving credit facility. The carrying amount of cash, receivables and payables approximates fair value because of the short-term nature of the instruments. The fair value of the revolving credit facility approximates its carrying value based on the borrowing rates currently available to the Partnership for bank loans with similar terms and maturities.

Accrued Liabilities

Accrued liabilities consists of the following:



	December 31,
	2019		2018
	(In thousands)
Capital expenditures accrued	$	42,160	$	37,984
Direct operating expense accrued	22,119		7,541
Sourced water purchases accrued	9,531		4,670
Other	2,815		1,609
Total accrued liabilities	$	76,625	$	51,804

Asset Retirement Obligations

The Partnership recognizes a liability based on the estimated costs of retiring tangible long-lived assets. The liability is recognized at its fair value and measured using expected discounted future cash outflows of the ARO when the obligation originates, which generally is when an asset is acquired or constructed. The carrying amount of the associated asset is increased commensurate with the liability recognized. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Subsequent to the initial recognition, the liability is adjusted for any changes in the expected value of the retirement obligation (with a corresponding adjustment to PP&E) and for accretion of the liability due to the passage of time, until the obligation is settled. If the fair value of the estimated obligation changes, an adjustment is recorded for both the retirement liability and the associated asset carrying amount. Revisions in estimated AROs may result from changes in estimated retirement costs and the estimated timing of settling the obligations.

Commitments and Contingencies

The Partnership may be a party to various legal proceedings, disputes and claims from time to time arising in the course of its business, including those that arise from interpretation of federal and state laws and regulations regarding air and water quality, hazardous and solid waste disposal and other environmental matters. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum amount of the range is accrued. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment.

Member’s Equity

In the accompanying balance sheets, member’s equity represents Diamondback’s historical investment in the Partnership, the Partnership’s accumulated net results, and the net effect of transactions with, and allocations from, Diamondback.

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Notes to Consolidated Financial Statements - (Continued)

Accumulated Other Comprehensive Income

The following table provides changes in the components of accumulated other comprehensive income, net of related income tax effects:



	(In thousands)
Balance as of December 31, 2018	$	—
Other comprehensive loss before reclassifications	(823		)
Change in accumulated other comprehensive income	(823		)
Balance as of December 31, 2019	$	(823	)

Revenue Recognition

Midstream revenues are comprised of crude oil and natural gas gathering and transportation services, produced water gathering and disposal and water sourcing and distribution services. The Partnership provides gathering and compression and water handling and treatment services under fee-based contracts based on throughput. Under these arrangements, the Partnership receives fees for gathering crude oil and natural gas, compression services, and water handling, disposal, and treatment services. The revenue the Partnership earns from these arrangements is directly related to (i) in the case of natural gas gathering and compression, the volumes of metered natural gas that the Partnership gathers, compresses, transports and delivers to natural gas to other transmission delivery points, (ii) in the case of oil gathering, the volumes of metered oil that the Partnership gathers, transports and delivers to other transmission delivery points, (iii) in the case of sourced water services, the quantities of sourced water obtained, transported and delivered to the Partnership’s customers for use in their well drilling and completion operations and (iv) in the case of produced water gathering and disposal services, the quantities of produced water gathered, transported and disposed of for the Partnership’s customers. The Partnership recognizes revenue when it satisfies a performance obligation by delivering a service to a customer. The Partnership earns substantially all of its midstream revenues from commercial agreements with Diamondback and its affiliates.

Real Estate Revenue Recognition

The Partnership recognizes rental revenue from tenants on a straight-line basis over the lease term when collectability is reasonably assured and the tenant has taken possession or controls the physical use of the leased asset. Rental income—related party is comprised of revenues earned from lease agreements with Diamondback and its affiliates. Other real estate revenue is derived from tenants’ use of parking, telecommunications and miscellaneous services. Parking and other miscellaneous service revenue is recognized when the related services are utilized by the tenants. Tenant recoveries related to reimbursement of real estate taxes, insurance, repairs and maintenance and other operating expenses are recognized as revenue in the period the applicable expenses are incurred. The reimbursements are recognized and presented gross, as the Partnership is generally the primary obligor with respect to purchasing goods and services from third-party suppliers, has discretion in selecting the supplier and bears the associated credit risk.

Concentrations

The Partnership derives substantially all of its revenue from our commercial agreements with Diamondback, which carry initial terms ending in 2034. The Partnership operates produced water disposal wells with other working interest owners. The revenues and expenses related to these disposal activities are reported on a net basis as part of revenues and costs and expenses.

Income Taxes

The Partnership is treated as a corporation for U.S. federal income tax purposes as a result of its election to be treated as a corporation effective May 24, 2019. Subsequent to the effective date of the Partnership’s election, it is subject to U.S. federal and state income tax at corporate rates. The Partnership uses 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 bases of existing assets and liabilities and (ii) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities

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Notes to Consolidated Financial Statements - (Continued)

is recognized in income in the period the rate change is enacted. A valuation allowance is provided for deferred tax assets when it is more likely than not the deferred tax assets will not be realized.

The Partnership is subject to margin tax in the state of Texas pursuant to the Tax Sharing Agreement with Diamondback, as discussed further in Note 14—Income Taxes. In addition to the Partnership’s 2019 tax year, the Predecessor’s 2016 through 2018 tax years, the periods during which the Predecessor’s sole owner, Diamondback, was responsible for federal income taxes on the Predecessor’s taxable income, remain open to examination by tax authorities. As of December 31, 2019, the Partnership had no unrecognized tax benefits that would have a material impact on the effective tax rate. The Partnership is continuing its practice of recognizing interest and penalties related to income tax matters as interest expense and general and administrative expenses, respectively. During the year ended December 31, 2019, there was no interest or penalties associated with uncertain tax positions recognized in the Partnership’s consolidated financial statements.

Capital Contributions

A contribution of a set of assets and related liabilities (a “set”) to the Partnership from Diamondback is analyzed to determine whether the set meets the definition of a business in Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) Topic 805, “Business Combinations”. A contribution of a set of assets that does not constitute a business is recognized at the date of the transfer at its carrying amount in the accounts of Diamondback in accordance with the guidance regarding transactions between entities under common control in ASC 805-50. Management then evaluates whether the asset contribution results in a change in the reporting entity, as defined in ASC Topic 250, “Accounting Changes and Error Corrections”. An asset contribution that does not constitute a change in the reporting entity is accounted for prospectively from the date of the transfer, while an asset contribution that constitutes a change in the reporting entity would result in retrospective application of the transaction.

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Notes to Consolidated Financial Statements - (Continued)

Recent Accounting Pronouncements

The Partnership considers the applicability and impact of all ASUs. ASUs not listed below were assessed and determined to be either not applicable or clarifications of ASUs previously disclosed. The following table provides a brief description of recent accounting pronouncements and the Partnership’s analysis of the effects on its financial statements:



Standard	Description	Date of Adoption	Effect on Financial Statements or Other Significant Matters
Recently Adopted Pronouncements
ASU 2016-13, “Financial Instruments - Credit Losses”	This update affects entities holding financial assets and net investment in leases that are not accounted for at fair value through net income. The amendments affect loans, debt securities, trade receivables, net investments in leases, off-balance sheet credit exposures, reinsurance receivables, and any other financial assets not excluded from the scope that have the contractual right to receive cash.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have a history of credit losses.
ASU 2018-13, “Fair Value Measurement (Topic 820) - Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement”	This update modifies the fair value measurement disclosure requirements specifically related to Level 3 fair value measurements and transfers between levels.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have transfers between fair value levels.
ASU 2018-15, “Intangibles - Goodwill and Other - Internal - Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract”	This update requires the capitalization of implementation costs incurred in a hosting arrangement that is a service contract for internal-use software. Training and certain data conversion costs cannot be capitalized. The entity is required to expense the capitalized implementation costs over the term of the hosting agreement.	Q1 2020	The Partnership adopted this update prospectively effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any capitalized implementation costs.
ASU 2019-05, “Financial Instruments-Credit Losses (Topic 326)”	This update allows a fair value option to be elected for certain financial assets, other than held-to-maturity debt securities, that were previously required to be measured at amortized cost basis.	Q1 2020	The Partnership adopted this update effective January 1, 2020. The adoption of this update did not have an impact on its financial position, results of operations or liquidity since it does not have any cost method investments.
Pronouncements Not Yet Adopted
ASU 2019-12, “Income Taxes (Topic 740) - Simplifying the Accounting for Income Taxes”	This update is intended to simplify the accounting for income taxes by removing certain exceptions and by clarifying and amending existing guidance.	Q1 2021	This update is effective for public business entities beginning after December 15, 2020 with early adoption permitted. The Partnership does not believe the adoption of this standard will have an impact on its financial position, results of operations or liquidity.

3. REVENUE FROM CONTRACTS WITH CUSTOMERS

The Partnership generates revenues by charging fees on a per unit basis for gathering crude oil and natural gas, delivering and storing sourced water, and collecting, recycling and disposing of produced water. The Partnership adopted ASC Topic 606, “Revenue from Contracts with Customers” (“ASC Topic 606”) on January 1, 2018, using the modified retrospective method. Under ASC Topic 606, performance obligations are the unit of account and generally represent distinct goods or services that are promised to customers. The adoption of ASC Topic 606 did not have a material impact on the recognition, measurement and presentation of the Partnership’s revenues and expenses.

Performance Obligations: For gathering crude oil and natural gas, delivering sourced water, and collecting, recycling and disposing of produced water, the Partnership’s performance obligations are satisfied over time using volumes delivered to measure progress. The Partnership records revenue related to the volumes delivered at the contract price at the time of delivery.

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Notes to Consolidated Financial Statements - (Continued)

The Partnership began generating revenue from water sales during first quarter 2018 upon the contribution of sourced water assets from Diamondback. For its water sales, each unit sold is generally considered a distinct good and the related performance obligation is generally satisfied at a point in time (i.e. at the time control of the water is transferred to the customer). The Partnership recognizes revenue from the sale of water when its contracted performance obligation to deliver water is satisfied and control of the water is transferred to the customer. This usually occurs when the water is delivered to the location specified in the contract and the title and risks of rewards and ownership are transferred to the customer.

Transaction Price Allocated to Remaining Performance Obligations: The majority of the Partnership’s revenue agreements have a term greater than one year and, as such, the Partnership has utilized the practical expedient in ASC Topic 606, which states that the Partnership is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under its revenue agreements, each delivery generally represents a separate performance obligation; therefore, future volumes delivered are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

The remainder of the Partnership’s revenue agreements, which relate to agreements with third parties, are short-term in nature with a term of one year or less. The Partnership has utilized an additional practical expedient in ASC Topic 606 which exempts it from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of an agreement that has an original expected duration of one year or less.

Contract Balances: Under the Partnership’s revenue agreements, the Partnership invoices customers after the Partnership’s performance obligations have been satisfied, at which point payment is unconditional. As such, the Partnership’s revenue agreements do not give rise to contract assets or liabilities under ASC Topic 606.

The following is a summary of the Partnership’s types of revenue agreements:


•	Crude Oil Gathering Agreement. Under the crude oil gathering agreements, the Partnership receives a volumetric fee per Bbl for gathering and delivering crude oil produced within the dedicated acreage.


•	Gas Gathering and Compression Agreement. Under the gas gathering and compression agreement, the Partnership receives a volumetric fee per MMBtu for gathering and processing all natural gas produced by Diamondback within the dedicated acreage.

•

Produced and Flowback Water Gathering and Disposal Agreements. Under the produced and flowback water gathering and disposal agreements, the Partnership receives a fee for gathering or disposing of water produced from operating crude oil and natural gas wells within the dedicated acreage. The fee is comprised of a volumetric fee per Bbl for the produced water services the Partnership provides. In addition, the Partnership retains the skim oil that is a part of the produced water. The skim oil is processed by a third party, which provides the Partnership a volumetric fee per Bbl.

•

Sourced Water Purchase and Services Agreements. Under the sourced water purchase and services agreements, the Partnership receives a fee for sourcing, transporting and delivering all raw sourced water and recycled sourced water required by Diamondback and third parties to carry out its oil and natural gas activities within the dedicated acreage. The fee is comprised of a volumetric fee per Bbl for the type of sourced water services the Partnership provides.

Real Estate Contracts: The Partnership recognizes rental revenue from tenants on a straight-line basis over the lease term when collectability is reasonably assured and the tenant has taken possession or controls the physical use of the leased asset. Rental income—related party is comprised of revenues earned from lease agreements with Diamondback and its affiliates. Other real estate revenue is derived from tenants’ use of parking, telecommunications and miscellaneous services. Parking and other miscellaneous service revenue is recognized when the related services are utilized by the tenants. Tenant recoveries related to reimbursement of real estate taxes, insurance, repairs and maintenance and other operating expenses are recognized as revenue in the period the applicable expenses are incurred. The reimbursements are recognized and presented gross, as the Partnership is generally the primary obligor with respect to purchasing goods and services from third-party suppliers, has discretion in selecting the supplier and bears the associated credit risk.

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Notes to Consolidated Financial Statements - (Continued)

It is noted that surface revenue, rental and real estate income and amortization of out of market leases is outside the scope of ASC Topic 606.

Disaggregation of Revenue

In the following table, revenue is disaggregated by type of service and type of fee. The table also identifies the operating business segment to which the disaggregated revenues relate. For more information on operating business segments, see Note 19—Report of Operating Business Segments.



	Year Ended December 31,
	2019		2018		2017		Segment
	(In thousands)
Type of Service:
Sourced water gathering	$	115,135	$	76,976	$	—	Midstream
Produced water gathering and disposal	275,882		72,352		27,864		Midstream
Crude oil gathering	27,206		16,038		7,641		Midstream
Natural gas gathering	14,317		6,447		2,909		Midstream
Surface revenue (non ASC 606 revenues)	904		875		881		Midstream
Real estate contracts (non ASC 606 revenues)	14,229		11,779		—		Real Estate
Total revenues	$	447,673	$	184,467	$	39,295

4. ACQUISITIONS

Ajax and Energen Assets

Effective January 1, 2019, Diamondback contributed to the Predecessor certain midstream assets (the “Ajax Assets”) within the Permian Basin that it acquired from Ajax Resources LLC (“Ajax”) as part of an upstream acquisition in the fourth quarter of 2018. These assets included 17 water wells, four produced water disposal wells and one related gathering system, a field office, surface land, five hydraulic fracturing pits and one related sourced water transportation system. Prior to their contribution, these assets were fully integrated into the upstream business acquired from Ajax. The carrying value of assets included in this contribution was $21.5 million. The contributed assets were recognized by the Predecessor at Diamondback’s historical basis due to the entities being under common control.

Effective January 1, 2019, Diamondback contributed to the Predecessor certain midstream assets (“the Energen Assets”) within the Permian Basin that it acquired from Energen Corporation (“Energen”) as part of an upstream acquisition in the fourth quarter of 2018. These assets included 56 produced water disposal wells and related gathering systems, an office building located in Midland Texas, surface land and an oil gathering system and asset retirement obligations related to these assets. Prior to their contribution, these assets were fully integrated into the upstream business acquired from Energen. The carrying value of assets included in this contribution was $279.0 million, net of $3.0 million in associated asset retirement obligations. The contributed assets were recognized by the Predecessor at Diamondback’s historical basis due to the entities being under common control.

The contribution of the Ajax and Energen Assets was an asset contribution that did not result in a change in the reporting entity at the Predecessor. As a result, the Ajax and Energen Assets were initially recognized at the date of the transfer at their carrying amounts in the accounts of Diamondback, and presented prospectively from that date.

Sourced Water Assets

In connection with its business operations, Diamondback constructed and/or acquired various sourced water assets, including certain wells, sourced water transportation lines and related assets (the “Sourced Water Assets”), located in the Delaware and Midland Basins of the Permian Basin. Effective January 1, 2018, Diamondback contributed the Sourced Water Assets to the Predecessor. The carrying value of assets included in this contribution was $32.8 million and $6.0 million of that amount related to sourced water inventory. The contributed assets were recognized by the Partnership at Diamondback’s historical basis due to the entities being under common control.

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Notes to Consolidated Financial Statements - (Continued)

The contribution of the Sourced Water Assets was an asset contribution that did not result in a change in the reporting entity at the Predecessor. As a result, the Sourced Water Assets were initially recognized at the date of the transfer at their carrying amounts in the accounts of Diamondback, and presented prospectively from that date.

Tall Towers

On January 31, 2018, Diamondback, through Tall Towers, acquired from Fasken Midland certain real property and related assets in Midland, Texas for a purchase price of approximately $110.0 million. All of the membership interests in Tall Towers were contributed to the Predecessor effective January 31, 2018. Diamondback allocated the purchase price between the tangible assets, consisting of land and two office towers, and to identified intangible lease assets. The contributed assets were recognized by the Predecessor at Diamondback’s historical basis due to the entities being under common control.

Midstream Assets and Land

In connection with its business operations, Diamondback constructed and/or acquired various midstream assets located in the Delaware and Midland Basins of the Permian Basin. Upon asset completion dates during 2018, Diamondback contributed the midstream assets to the Predecessor. Such midstream assets include produced water disposal gathering assets and wells with a carrying value of $18.2 million, land valued at $1.5 million, and a field office valued at $1.3 million. The contributed assets were recognized by the Predecessor at Diamondback’s historical basis due to the entities being under common control.

Other Acquisitions

During the fourth quarter of 2019, the Partnership acquired three produced water disposal wells and related assets in the Delaware basin and one produced water disposal well and related assets in the Midland basin for an aggregate of $17.3 million, subject in each cash to certain adjustments, which collectively increased disposal capacity by 65,000 barrels per day.

5. REAL ESTATE ASSETS

In conjunction with Diamondback’s contribution of Tall Towers, the Predecessor allocated the $110.0 million purchase price between real estate assets and intangible lease assets related to in-place and above-market leases. During the year ended December 31, 2018, Diamondback also contributed a field office with a fair value of $1.3 million to the Operating Company. During the three months ended March 31, 2019, as part of the Energen contribution, Diamondback contributed an office building located in Midland Texas with a value of $9.2 million. The following schedules present the cost and related accumulated depreciation or amortization (as applicable) of the Partnership’s real estate assets and intangible lease assets:



		As of December 31,
	Weighted Average Useful Lives	2019			2018
	(Years)	(In thousands)
Buildings	20-30	$	102,375		$	92,349
Tenant improvements	15	4,501			4,160
Land improvements	15	484			484
Total real estate assets		107,360			96,993
Less: accumulated depreciation		(8,681		)	(3,970		)
Total investment in real estate, net		$	98,679		$	93,023

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Notes to Consolidated Financial Statements - (Continued)



		As of December 31,
	Weighted Average Useful Lives	2019			2018
	(Months)	(In thousands)
In-place lease intangibles	45	$	11,389		$	10,866
Less: accumulated amortization		(5,927		)	(3,076		)
In-place lease intangibles, net		5,462			7,790

Above-market lease intangibles	45	3,623			3,623
Less: accumulated amortization		(1,015		)	(459		)
Above-market lease intangibles, net		2,608			3,164
Total intangible lease assets, net		$	8,070		$	10,954

Depreciation and amortization expense for real estate assets was $7.6 million and $7.0 million for the years ended December 31, 2019 and 2018, respectively. There was no depreciation and amortization expense for real estate assets for the year ended 2017.

The estimated amortization expense related to lease intangibles for the next five succeeding fiscal years is approximately $8.1 million.

6. PROPERTY, PLANT AND EQUIPMENT

The following table sets forth the Partnership’s property, plant and equipment:



	Estimated	As of December 31,
	Useful Lives	2019			2018
	(Years)	(In thousands)
Produced water disposal systems	10-30	$	600,797		$	220,084
Crude oil gathering systems⁽¹⁾	30	129,658			66,760
Natural gas gathering and compression systems⁽¹⁾	10-30	98,426			60,350
Sourced water gathering systems⁽¹⁾	30	101,887			68,694
Total property, plant and equipment		930,768			415,888
Land	N/A	88,509			70,373
Less: accumulated depreciation, amortization and accretion		(61,132		)	(28,317		)
Total property, plant and equipment, net		$	958,145		$	457,944


(1)	Included in gathering systems are $138.6 million and $55.2 million of assets at December 31, 2019 and December 31, 2018, respectively, that are not subject to depreciation, amortization and accretion as the systems were under construction and had not yet been put into service.

Depreciation expense related to property, plant and equipment was $33.2 million, $18.1 million and $3.5 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Internal costs capitalized to property, plant and equipment represent management’s estimate of costs incurred directly related to construction activities. Capitalized internal costs were approximately $5.1 million for the year ended December 31, 2019. There were no capitalized internal costs for the years ended 2018 and 2017.

At December 31, 2019, there was $1.8 million of capitalized interest that was related to property, plant and equipment.

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Notes to Consolidated Financial Statements - (Continued)

During the year ended December 31, 2019, the Partnership incurred losses related to weather damage at certain produced water disposal facilities. The damage totaled $7.5 million, for which the Partnership expects insurance proceeds of $6.0 million, resulting in a loss of $1.5 million.

7. ASSET RETIREMENT OBLIGATIONS

Asset retirement obligations consist primarily of estimated costs of dismantlement, removal, site reclamation, plugging and abandonment and similar activities associated with the Partnership’s infrastructure assets. The following table reflects the changes in the Partnership’s asset retirement obligation for the following periods:



	Year Ended December 31,
	2019			2018		2017
	(In thousands)
Asset retirement obligation, beginning of period	$	561		$	383	$	194
Liabilities incurred	9,188			143		166
Liabilities settled	(21		)	—		—
Estimates revised	5			—		—
Accretion expense during period	1,614			35		23
Asset retirement obligation, end of period	$	11,347		$	561	$	383

8. EQUITY METHOD INVESTMENTS

At December 31, 2019 and 2018, the carrying values of the Partnership’s equity method investments are as follows:



	Ownership Interest		December 31, 2019		December 31, 2018
			(In thousands)
EPIC Crude Holdings, LP	10	%	$	109,806	$	—
Gray Oak Pipeline, LLC	10	%	115,840		—
Wink to Webster Pipeline LLC	4	%	34,124		—
OMOG JV LLC	60	%	219,098		—
Amarillo Rattler, LLC	50	%	690		—
Total			$	479,558	$	—

The following summarizes the income (loss) of equity method investees reflected in the Consolidated Statement of Operations.



	Year Ended December 31,
	2019			2018		2017
	(In thousands)
EPIC Crude Holdings, LP	$	(6,597	)	$	—	$	—
Gray Oak Pipeline, LLC	831			—		—
Wink to Webster Pipeline LLC	(539		)	—		—
OMOG JV LLC	(24		)	—		—
HMW LLC	—			—		1,366
Total	$	(6,329	)	$	—	$	1,366

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Notes to Consolidated Financial Statements - (Continued)

In October 2014, Diamondback obtained a 25% interest in HMW Fluid Management LLC (“HMW LLC”), which was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to exploration and production companies operating in Midland, Martin and Andrews Counties, Texas.

On June 30, 2018, HMW LLC’s operating agreement was amended. As a result of the amendment, the Partnership no longer recognizes an equity method investment in HMW LLC but instead consolidates its undivided interest in the produced water disposal assets owned by HMW LLC. In exchange for the Partnership’s 25% investment, the Partnership received a 50% undivided ownership interest in two of the four produced water disposal wells and associated assets previously owned by HMW LLC. The Partnership’s basis in the assets is equivalent to its basis in the equity method investment in HMW LLC.

On February 1, 2019, Diamondback funded and the Predecessor acquired a 10% equity interest in EPIC Crude Holdings, LP (“EPIC”), which is building a pipeline (the “EPIC pipeline”) that, once fully operational, will transport crude and natural gas liquids across Texas for delivery into the Corpus Christi market. The EPIC pipeline began initial operations during the third quarter of 2019.

On February 15, 2019, Diamondback funded and the Predecessor acquired a 10% equity interest in Gray Oak Pipeline, LLC (“Gray Oak”), which is building a pipeline (the “Gray Oak pipeline”) that, once operational, will transport crude from the Permian to Corpus Christi on the Texas Gulf Coast. The Gray Oak pipeline began initial operations during the fourth quarter of 2019.

On March 29, 2019, the Predecessor executed a short-term promissory note to Gray Oak. The note allows for borrowing by Gray Oak of up to $123.0 million at 2.52% interest rate with a maturity date of March 31, 2022. During the year ended December 31, 2019, Gray Oak borrowed and repaid $22.6 million under this note. The short-term promissory note was repaid on May 31, 2019.

On June 4, 2019, the Partnership entered into an equity contribution agreement with respect to Gray Oak. The equity contribution agreement requires the Partnership to contribute equity or make loans to Gray Oak so that Gray Oak can, to the extent necessary, cure payment defaults under Gray Oak’s credit agreement and, in certain instances, repay Gray Oak’s credit agreement in full. The Partnership’s obligations under the equity contribution agreement are limited to its proportionate ownership interest in Gray Oak, and such obligations are guaranteed by the Operating Company, Tall Towers, Rattler OMOG LLC and Rattler Ajax Processing LLC.

On July 30, 2019, the Operating Company joined Wink to Webster Pipeline LLC as a 4% member, together with affiliates of ExxonMobil, Plains All American Pipeline, Delek US, MPLX LP, and Lotus Midstream. The joint venture is developing a crude oil pipeline with origin points at Wink and Midland in the Permian Basin for delivery to multiple Houston area locations (the “Wink to Webster pipeline”). The Wink to Webster pipeline is expected to begin service in the first half of 2021.

On October 1, 2019, the Partnership acquired a 60% equity interest in OMOG JV LLC (“OMOG”). On November 7, 2019, OMOG acquired 100% of Reliance Gathering, LLC which owns and operates a crude oil gathering system in the Permian, and was renamed as Oryx Midland Oil Gathering LLC following the acquisition. While the Partnership’s equity interest is 60%, the investment is accounted for as an equity method investment as the Partnership does not control operating activities and substantive participating rights exist with the controlling minority investor.

On December 20, 2019, the Partnership acquired a 50% equity interest in Amarillo Rattler, LLC, which currently owns and operates the Yellow Rose gas gathering and processing system with estimated total processing capacity of 40,000 Mcf/d and over 84 miles of gathering and regional transportation pipelines in Dawson, Martin and Andrews Counties, Texas. This joint venture also intends to construct and operate a new 60,000 Mcf/d cryogenic natural gas processing plant in Martin County, Texas, as well as incremental gas gathering and compression and regional transportation pipelines. While the Partnership’s equity interest is 50%, the investment is accounted for as an equity method investment as the Partnership does not control operating activities and substantive participating rights exist with the controlling investor.

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Notes to Consolidated Financial Statements - (Continued)

using the cost method or the equity method. Investments of greater than 3% to 5% are considered more than minor and, therefore, should be accounted for using the equity method. For investments where the Partnership has less than a 20% ownership interest, the investment is accounted for as an equity method investment as the Partnership has the ability to exercise significant influence.

Summarized Financial Information

The following tables sets forth summarized financial information of the investments in which the Partnership acquired an interest in 2019, as follows:



	As of
	December 31,
	2019
	(In thousands)
Balance Sheet
Current assets	$	550,624
Property, plant and equipment	5,190,371
Other assets	196,470
Total assets	5,937,465
Current liabilities	516,155
Other liabilities	2,051,110
Member's Equity	3,370,200
Total liabilities and member's equity	$	5,937,465



	Year Ended
	December 31,
	2019
Income Statement	(In thousands)
Revenue	$	53,898
Operating expenses	$	116,400
Net income	$	(72,227	)

The carrying value of the Partnership’s equity method investments as of December 31, 2019 was as follows:



	Year Ended
	December 31,
	2019
	(In thousands)
Carrying value of equity method investments	$	479,558

As of December 31, 2019, there was an aggregate difference of $7.0 million between the carrying amounts of these investments and the amounts of underlying equity in net assets of these investments. The Partnership's basis in these assets includes certain capitalized formation costs and basis differences related to the Partnership's initial investment into each asset above carrying value.

No impairments were recorded for the Partnership’s equity method investments for the years ended December 31, 2019 or 2018.

At December 31, 2019, there was $0.9 million of capitalized interest that was related to equity method investments that have not yet begun operations.

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9. DEBT

Long-term debt consisted of the following as of the dates indicated:



	As of
	December 31, 2019		December 31, 2018
	(In thousands)
Operating Company revolving credit facility	$	424,000	$	—
Total long-term debt	$	424,000	$	—

Credit Agreement—Wells Fargo

The Partnership, as parent, and the Operating Company, as borrower, entered into a credit agreement, dated May 28, 2019, (as amended, the “Credit Agreement”) with Wells Fargo Bank, National Association, as administrative agent, and a syndicate of banks, including Wells Fargo Bank, National Association, as lenders party thereto.

The Credit Agreement provides for a revolving credit facility in the maximum amount of $600.0 million. Loan principal may be optionally repaid from time to time without premium or penalty (other than customary LIBOR breakage), and is required to be paid at the maturity date of May 28, 2024. The loan is guaranteed by the Partnership, Tall Towers, Rattler OMOG LLC and Rattler Ajax Processing LLC and is secured by substantially all of our, the Operating Company and the other guarantors’ assets. As of December 31, 2019, the Operating Company had $424.0 million of outstanding borrowings and $176.0 million available for future borrowings under the Credit Agreement.

The outstanding borrowings under the Credit Agreement bear interest at a per annum rate elected by the Operating Company that is based on the prime rate or LIBOR, in each case plus an applicable margin. The applicable margin ranges from 0.250% to 1.250% per annum 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.

The Credit Agreement contains various affirmative and negative covenants. These covenants, among other things, limit additional indebtedness, additional liens, sales of assets, mergers and consolidations, distributions and other restricted payments, transactions with affiliates, and entering into certain swap agreements, in each case of the Partnership, the Operating Company and their restricted subsidiaries. The covenants are subject to exceptions set forth in the Credit Agreement, including an exception allowing the Partnership or the Operating Company to issue unsecured debt securities and an exception allowing payment of distributions if no default exists. The Credit Agreement may be used to fund capital expenditures, to finance working capital, for general company purposes, to pay fees and expenses related to the Credit Agreement, and to make distributions permitted under the Credit Agreement.

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Notes to Consolidated Financial Statements - (Continued)

The Credit Agreement also contains financial maintenance covenants that require the maintenance of the financial ratios described below:



Financial Covenant		Required Ratio
Consolidated Total Leverage Ratio		Not greater than 5.00 to 1.00 (or not greater than 5.50 to 1.00 for 3 fiscal quarters following certain acquisitions), but if the Consolidated Senior Secured Leverage Ratio (as defined in the Credit Agreement) is applicable, then not greater than 5.25 to 1.00)
Consolidated Senior Secured Leverage Ratio commencing with the last day of any fiscal quarter in which the Financial Covenant Election (as defined in the Credit Agreement) is made		Not greater than 3.50 to 1.00
Consolidated Interest Coverage Ratio (as defined in the Credit Agreement)		Not less than 2.50 to 1.00

For purposes of calculating the financial maintenance covenants prior to the fiscal quarter ending June 30, 2020, EBITDA (as defined in the Credit Agreement) will be annualized based on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019.

As of December 31, 2019, each of the Partnership and the Operating Company was in compliance with all financial covenants under the Credit Agreement. The lenders may accelerate all of the indebtedness under the Credit Agreement upon the occurrence and during the continuance of any event of default. The Credit Agreement contains customary events of default, including non-payment, breach of covenants, materially incorrect representations, cross-default, bankruptcy and change in control. There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial maintenance covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. With certain specified exceptions, the terms and provisions of the Credit Agreement generally may be amended with the consent of the lenders holding a majority of the outstanding loans or commitments to lend.

10. UNIT-BASED COMPENSATION

On May 22, 2019, the board of directors of the General Partner adopted the Rattler Midstream LP Long Term Incentive Plan (“LTIP”), for employees, consultants and directors of the General Partner and any of its affiliates, including Diamondback, who perform services for the Partnership. 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. As of December 31, 2019, a total of 15,151,515 common units had been reserved for issuance pursuant to the LTIP. Common units that are cancelled, forfeited or withheld to satisfy exercise prices or tax withholding obligations will be available for delivery pursuant to other awards. The LTIP is administered by the board of directors of the General Partner or a committee thereof.

For the year ended December 31, 2019, the Partnership incurred $5.2 million of unit-based compensation.

Phantom Units

Under the LTIP, the board of directors of the General Partner is authorized to issue phantom units to eligible employees and non-employee directors. The Partnership estimates the fair value of phantom units as the closing price of the Partnership’s common units on the grant date of the award, which is expensed over the applicable vesting period. Upon vesting, the phantom units entitle the recipient to one common unit of the Partnership for each phantom unit. The recipients are also entitled to distribution equivalent rights, which represent the right to receive a cash payment equal to the value of the distributions paid on one phantom unit between the grant date and the vesting date.

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Notes to Consolidated Financial Statements - (Continued)

The following table presents the phantom unit activity under the LTIP for the year ended December 31, 2019:



	Phantom Units		Weighted Average Grant-Date Fair Value
Unvested at May 28, 2019	—		$	—
Granted	2,284,038		$	19.14
Forfeited	(57,143	)	$	19.21
Unvested at December 31, 2019	2,226,895		$	19.14

As of December 31, 2019, the unrecognized compensation cost related to unvested phantom units was $37.4 million. Such cost is expected to be recognized over a weighted-average period of 2.4 years.

11. UNITHOLDERS’ EQUITY AND PARTNERSHIP DISTRIBUTIONS

The Partnership has general partner and limited partner units. At December 31, 2019, the Partnership had a total of 43,700,000 common units issued and outstanding and 107,815,152 Class B units issued and outstanding, of which no common units and 107,815,152 Class B units were owned by Diamondback, representing approximately 71% of the Partnership’s total units outstanding. The Operating Company units and the Partnership’s Class B units owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).

The following table summarizes changes in the number of the Partnership’s common units:



	Common Units
Balance at May 28, 2019	—
Common units issued in public offerings	43,700,000
Balance at December 31, 2019	43,700,000

The following table summarizes changes in the number of the Partnership’s class B units:



	Class B Units
Balance at May 28, 2019	—
Units related to tax conversion	107,815,152
Balance at December 31, 2019	107,815,152

At the closing of the Partnership’s IPO, the board of directors of the General Partner adopted a policy pursuant to which the Partnership will pay, to the extent legally available, cash distributions of $0.25 per common unit to common unitholders of record on the applicable record date within 60 days after the end of each quarter beginning with the quarter ending September 30, 2019. The Partnership’s first distribution was prorated for the period from the closing of the IPO through September 30, 2019. On February 13, 2020, the board of directors of the General Partner revised the cash distribution policy to provide that the Partnership will pay, to the extent legally available, cash distributions of $0.29 per common unit to common unitholders of record on the applicable record date after the end of each quarter beginning the quarter ended December 31, 2019. The board of directors of the General Partner may change the Partnership’s distribution policy at any time and from time to time. The partnership agreement (discussed below) does not require the Partnership to pay cash distributions on the Partnership’s common units on a quarterly or other basis.

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Notes to Consolidated Financial Statements - (Continued)

The following table presents cash distributions approved by the board of directors of the General Partner for the periods presented:



Declaration Date	Quarter	Amount per Common Unit		Payment Date
October 31, 2019	Q3 2019	$	0.34	November 22, 2019
February 13, 2020	Q4 2019	$	0.29	March 10, 2020

12. EARNINGS PER COMMON UNIT

The net income per common unit on the consolidated statements of operations is based on the net income of the Partnership for the period after the closing of the IPO on May 28, 2019 through December 31, 2019, since this is the amount of net income that is attributable to the Partnership’s common units.

The Partnership’s net income is allocated wholly to the common units, as the General Partner does not have an economic interest.

Basic and diluted net income per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. Basic earnings per common unit is calculated by dividing net income by the weighted-average number of common units outstanding during the period. Diluted earnings per common unit also considers the dilutive effect of unvested common units granted under the LTIP, calculated using the treasury stock method.



	May 28, 2019 to
	December 31, 2019
	(In thousands, except per unit amounts)
Net income attributable to Rattler Midstream LP	$	28,802
Less: net income allocated to participating securities⁽¹⁾	(751		)
Net income attributable to common unitholders	28,051
Weighted average common units outstanding:
Basic weighted average common units outstanding	43,622
Diluted weighted average common units outstanding	43,622
Net income per common unit, basic	$	0.64
Net income per common unit, diluted	$	0.64


(1)	Distribution equivalent rights granted to employees are considered participating securities.

The Partnership had the following units that were excluded from the computation of diluted earnings per unit because their inclusion would have been anti-dilutive for the periods presented but could potentially dilute basic earnings per unit in future periods:



	May 28, 2019 to
	December 31, 2019
	(in thousands)
Phantom units	44

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Notes to Consolidated Financial Statements - (Continued)

13. RELATED PARTY TRANSACTIONS

Partnership Agreement

At the closing of the IPO, the General Partner and Energen Resources Corporation, a subsidiary of Energen, entered into the first amended and restated agreement of limited partnership of Rattler Midstream LP, dated May 28, 2019 (the “Partnership Agreement”). The Partnership Agreement requires the Partnership to reimburse 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 set a limit on the amount of expenses for which its General Partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for the Partnership or on its behalf and expenses allocated to the General Partner by its affiliates. The General Partner is entitled to determine the expenses that are allocable to the Partnership. For the year ended December 31, 2019, the General Partner allocated $0.4 million of such expenses to the Partnership. The General Partner did not allocate any such expenses to the Partnership for the year ended December 31, 2018 and 2017.

Asset Contribution Agreement

In July 2018, the Predecessor entered into a contribution agreement with Diamondback by which Diamondback contributed certain assets to the Predecessor, including (i) the Rattler assets, (ii) Diamondback’s field office, certain produced water disposal wells, gathering and frac ponds in Reeves County, Texas (the “Luxe assets”), (iii) the Brigham assets, (iv) the sourced water assets, (v) certain of Diamondback’s real property interests in Glasscock, Howard, Martin, Midland, Pecos and Reeves Counties, Texas (the “land assets”), (vi) the Tall Towers interest, and (vii) 25% membership interests in HMW LLC that Diamondback had acquired in October 2014 (the “HMW Interest”).

The contribution of the Tall Towers interest was effective as of January 31, 2018.

HMW LLC was formed to develop, own and operate an integrated water management system to gather, store, process, treat, distribute and dispose of water to E&P companies operating in Midland, Martin and Andrews Counties, Texas. The contribution of the HMW Interest was effective as of January 1, 2016. The Predecessor recorded $1.4 million in income from investments associated with its interests in HMW LLC during fiscal year 2017. On June 30, 2018, HMW LLC’s operating agreement was amended, effective as of January 1, 2018. In exchange for its 25% investment, the Predecessor received a 50% undivided ownership interest in two of the four produced water disposal wells and associated assets previously owned by HMW LLC. The Predecessor’s basis in the assets was equivalent to its basis in the equity method investment in HMW LLC.

In February 2019, the Predecessor entered into a contribution agreement with Diamondback by which Diamondback contributed midstream assets to the Predecessor, including certain crude oil gathering, produced water disposal wells, land and buildings Diamondback had acquired pursuant to the Ajax acquisition on October 31, 2018 and the Energen acquisition on November 29, 2018. The contribution was effective as of January 1, 2019 and was comprised of approximately $297.6 million of net property, plant and equipment and $3.3 million of asset retirement obligations related to the contributed assets.

Services and Secondment Agreement

At the closing of the IPO, the Partnership entered into a services and secondment agreement with Diamondback, Diamondback E&P LLC, the General Partner and the Operating Company, dated as of May 28, 2019 (the “Services and Secondment Agreement”). Pursuant to the Services and Secondment Agreement, Diamondback and its subsidiaries second certain operational, construction, design and management employees and contractors of Diamondback to the General Partner, the Partnership and its subsidiaries, providing management, maintenance and operational functions with respect to the Partnership’s assets. The Services and Secondment Agreement requires the General Partner and the Partnership to reimburse Diamondback for the cost of the seconded employees and contractors, including their wages and benefits. For the year ended December 31, 2019, the General Partner and

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Notes to Consolidated Financial Statements - (Continued)

the Partnership paid Diamondback $5.1 million under the Services and Secondment Agreement. The General Partner and the Partnership did not pay Diamondback under the Services and Secondment Agreement for the year ended December 31, 2018 and 2017.

Commercial Agreements

The Partnership derives substantially all of its revenue from its commercial agreements with Diamondback for the provision of midstream services. For the year ended December 31, 2019, the Partnership received $9.9 million, $14.3 million, $271.6 million and $112.7 million under the terms of its crude oil gathering agreement, its gas gathering and compression agreement, its produced and flowback water gathering and disposal agreement and its sourced water services agreement with Diamondback, respectively. For the year ended December 31, 2018, the Predecessor received $16.0 million, $6.4 million, $72.4 million and $77.0 million under the terms of the Partnership’s crude oil gathering agreement, the Partnership’s gas gathering and compression agreement, the Partnership’s produced and flowback water gathering and disposal agreement and the Partnership’s sourced water services agreement with Diamondback, respectively. For the year ended December 31, 2017, the Predecessor received $7.6 million, $2.9 million and $27.9 million under the terms of the Partnership’s crude oil gathering agreement, the Partnership’s gas gathering and compression agreement and the Partnership’s produced and flowback water gathering and disposal agreement with Diamondback, respectively. The Predecessor did not provide water services to Diamondback in 2017.

Exchange Agreement

The Partnership entered into an exchange agreement with Diamondback, the General Partner and the Operating Company, under which Diamondback can tender Operating Company units and an equal number of Diamondback’s Class B units, together referred to as the tendered units, for redemption to the Operating Company and the Partnership. As consideration for the tendered units, Diamondback has the right to receive upon redemption, at the election of the Operating Company with the approval of the conflicts committee of the General Partner’s board of directors, either the number of the Partnership’s common units equal to the number of tendered units or a cash payment equal to the sum of (i) the number of tendered units multiplied by the average daily trading price of the Partnership’s common units for the prior 20 days plus (ii) the number of tendered units multiplied by the quotient of $1 million divided by the number of then outstanding Class B units. In addition, the Partnership has the right but not the obligation, to directly purchase such tendered units for, subject to the approval of the conflicts committee of the General Partner’s board of directors, cash or the Partnership’s common units at the Partnership’s election.

The exchange agreement also provides that, subject to certain exceptions, Diamondback does not have the right to exchange its Operating Company units if the Operating Company or if the Partnership determines that such exchange would be prohibited by law or regulation or would violate other agreements to which the Partnership may be subject, and the Operating Company and the Partnership may impose additional restrictions on the exchange that either of them determines necessary or advisable so that the Partnership is not treated as a “publicly traded partnership” for U.S. federal income tax purposes.

If the Operating Company elects to receive the Partnership’s common units in exchange for Diamondback’s tendered units, the exchange will be on a one-for-one basis, subject to adjustment in the event of splits or combinations of units, distributions of warrants or other unit purchase rights, specified extraordinary distributions and similar events. If the Operating Company elects to deliver cash in exchange for Diamondback’s tendered units, or if the Partnership exercises its right to purchase tendered units for cash, the amount of cash payable will be based on the average daily trading price of the Partnership’s common units for the prior 20 days.

Registration Rights Agreement

The Partnership entered into a registration rights agreement with Diamondback under which Diamondback is entitled to demand registration rights, including the right to demand that a shelf registration statement be filed, and “piggyback” registration rights, for common units that it owns or acquires, including through the exchange of Diamondback’s Class B units and the Partnership’s common units for Operating Company units in accordance with the exchange agreement.

Equity Contribution Agreement

Prior to the IPO, the Partnership entered into an equity contribution agreement with the Operating Company under which the Partnership contributed all of the net proceeds of the IPO to the Operating Company in exchange for 38,000,000 Operating Company units. The Operating Company used the contributed funds to make distributions to Diamondback and for general company purposes.

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Fasken Center Agreements

The Partnership has entered into a long-term lease agreement with Diamondback for certain office space located within the Fasken Center. Effective as of January 31, 2018, Diamondback contributed all of its membership interest in Tall Towers, which owns the Fasken Center in Midland, Texas, to the Operating Company pursuant to the asset contribution agreement. Diamondback is a tenant in the Fasken Center. For the year ended December 31, 2019, the Partnership received $5.2 million related to its lease agreement with Diamondback.

Tax Sharing Agreement

At the closing of the IPO, the Operating Company entered into a tax sharing agreement with Diamondback (the “Tax Sharing Agreement”). Pursuant to the Tax Sharing Agreement, the Operating Company reimburses Diamondback for its share of state and local income and other taxes borne by Diamondback as a result of the Operating Company’s results being included in a combined or consolidated tax return filed by Diamondback with respect to taxable periods including or beginning on May 28, 2019. The amount of any such reimbursement is limited to the tax 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 reimburse Diamondback for the tax the Operating Company would have owed had the tax attributes not been available or used for the Operating Company’s benefit, even though Diamondback had no cash tax expense for that period.

For the year ended December 31, 2019, the Partnership accrued state income tax expense of $0.2 million for its share of Texas margin tax for which the Partnership’s share of the Operating Company results are included in a combined tax return filed by Diamondback.

14. INCOME TAXES

Prior to the Partnership’s IPO, all of the membership interests of the Predecessor were owned by a single member. Under applicable federal income tax provisions, the Predecessor’s legal existence as an entity separate from its sole owner was disregarded for U.S. federal income tax purposes. As a result, the Predecessor’s owner, Diamondback, was responsible for federal income taxes on its share of the Predecessor’s taxable income. Similarly, the Predecessor had no tax attributes such as net operating loss carryforwards because such tax attributes are treated for federal income tax purposes as attributable to the Predecessor’s owner.

In certain circumstances, GAAP requires or permits entities such as the Predecessor to account for income taxes under the principles of ASC Topic 740, “Income Taxes” (“ASC Topic 740”), notwithstanding the fact that the separate legal entity’s activity is attributed to its owner for income tax purposes. Accordingly, the Predecessor has applied the principles of ASC Topic 740 to its financial statements herein, for periods prior to the Partnership’s IPO, as if the Predecessor had been subject to taxation as a corporation. Consistent with the overall basis of presentation as described in Note 1—Organization and Basis of Presentation, for the years ended December 31, 2019 and 2018, net income for the period prior to the Partnership’s IPO reflects income taxes based on federal and state income tax rates, net of federal benefit, applicable to the Predecessor as if it had been subject to taxation as a corporation. At the closing of the IPO, an adjustment of $31.1 million to equity of the Predecessor was recorded for the elimination of current and deferred tax liabilities related to the period prior to the IPO.

Subsequent to the Partnership’s IPO, the Partnership provides for income taxes under the asset and liability method. Deferred tax assets and liabilities are determined based on the difference between the financial statement and tax bases of assets and liabilities, specifically the Partnership’s investment in the Operating Company, using enacted tax rates expected to be in effect during the year in which the basis differences reverse. Valuation allowances are established when management determines it is more likely than not that some portion, or all, of the Partnership’s deferred tax assets will not be realized.

For the year ended December 31, 2019, net income for the period prior to the IPO reflects income tax expense of $18.2 million and net income from continuing operations for the period subsequent to the IPO reflects income tax expense of $8.1 million. For the years ended December 31, 2018 and 2017, net income of the Predecessor reflects income tax expense of $17.4 million and $4.7 million, respectively. Total income tax expense from continuing operations for the 2019 and 2018 periods differed from applying the U.S. statutory corporate income tax rate of 21% to pre-tax income primarily due to state income taxes, net of federal benefit, and due to net income attributable to the noncontrolling interest for the 2019 period subsequent to the IPO. In addition, total income tax expense of the Predecessor for the year ended December 31, 2017, differed from the U.S. statutory corporate income tax rate of 35% primarily due to deferred tax benefit of $4.5 million recognized as a result of the reduction in the carrying amount of its deferred tax assets and liabilities from 35% to the 21% federal statutory rate enacted in the fourth quarter of 2017.

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Notes to Consolidated Financial Statements - (Continued)

The components of the provision for income taxes from continuing operations for the years ended December 31, 2019, 2018 and 2017 are as follows:



	Year Ended December 31,
	2019 Subsequent to IPO		2019 Prior to IPO		2018		2017
			Predecessor		Predecessor		Predecessor
	(In thousands)
Current income tax provision:
Federal	$	—	$	7,694	$	11,089	$	—
State	189		270		425		217
Total current income tax provision	189		7,964		11,514		217
Deferred income tax provision:
Federal	7,600		9,983		5,689		4,237
State	282		235		156		234
Total deferred income tax provision	7,882		10,218		5,845		4,471
Total provision for income taxes	$	8,071	$	18,182	$	17,359	$	4,688

A reconciliation of the statutory federal income tax amount from continuing operations to the recorded expense is as follows:



	Year Ended December 31,
	2019 Subsequent to IPO			2019 Prior to IPO		2018		2017
	(In thousands)
Income tax expense at the federal statutory rate ⁽¹⁾	$	26,679		$	17,677	$	16,867	$	8,873
Impact of nontaxable noncontrolling interest	(18,982		)	—		—		—
State income tax expense, net of federal tax effect	372			505		492		317
Income tax benefit relating to change in statutory tax rate	—			—		—		(4,502		)
Other, net	2			—		—		—
Provision for income taxes	$	8,071		$	18,182	$	17,359	$	4,688

(1) The federal statutory rates for the years ended December 31, 2019, 2018 and 2017 were 21%, 21%, and 35%, respectively.

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Notes to Consolidated Financial Statements - (Continued)

The components of the deferred tax assets and liabilities as of December 31, 2019 and 2018 of the Partnership and the Predecessor are as follows:



	Year Ended December 31,
	2019		2018 Predecessor
	(In thousands)
Deferred tax assets
Net operating loss and other carryforwards (indefinite life)	$	232	$	—
Investment in the Operating Company	—		—
Other	—		—
Total deferred tax assets	232		—
Deferred tax liabilities
Investment in the Operating Company	8,059		—
Midstream assets	—		12,912
Other	—		—
Total deferred tax liabilities	8,059		12,912
Net deferred tax liabilities	$	7,827	$	12,912

The Partnership and Predecessor had net deferred tax liabilities of approximately $7.8 million and $12.9 million at December 31, 2019 and 2018, respectively. Subsequent to the deemed formation of the Operating Company as a partnership for federal income tax purposes upon the Partnership’s IPO, deferred taxes are no longer provided on the underlying assets and liabilities of the Predecessor but are provided on the difference between the Partnership’s basis for financial accounting purposes and basis for federal income tax purposes in its investment in the Operating Company. The Partnership incurred a tax net operating loss (“NOL”) in the current year due principally to the Operating Company’s tax deductions for accelerated depreciation, which exceeded its other items of taxable income. At December 31, 2019, the Partnership had approximately $0.2 million of federal NOLs with an indefinite carryforward life. The Partnership principally operates in the state of Texas and, for the year ended December 31, 2019, has accrued state income tax expense of $0.2 million for its share of Texas margin tax attributable to the Partnership’s results which are included in a combined tax return filed by Diamondback.

Management considers the likelihood that the Partnership’s net operating losses and other deferred tax attributes will be utilized prior to their expiration, if applicable. At December 31, 2019, management’s assessment included consideration of all available positive and negative evidence including the anticipated timing of reversal of deferred tax liabilities. As a result of the assessment, management determined that it is more likely than not that the Partnership will realize its deferred tax assets. At December 31, 2019, the Partnership did not have any significant uncertain tax positions requiring recognition in the financial statements.

15. FAIR VALUE MEASUREMENTS

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Valuation techniques used to measure fair value must maximize the use of observable inputs and minimize the use of unobservable inputs.

The fair value hierarchy is based on three levels of inputs, of which the first two are considered observable and the last unobservable, that may be used to measure fair value. The Partnership’s assessment of the significance of a particular input to the fair value measurements requires judgment and may affect the valuation of the assets and liabilities being measured and their placement within the fair value hierarchy. The Partnership uses appropriate valuation techniques based on available inputs to measure the fair values of its assets and liabilities.

Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.

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Notes to Consolidated Financial Statements - (Continued)

Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement.

The Partnership estimates asset retirement obligations pursuant to the provisions of FASB ASC Topic 410, “Asset Retirement and Environmental Obligations.” The initial measurement of asset retirement obligations at fair value is calculated using discounted cash flow techniques and based on internal estimates of future retirement costs associated with produced water disposal wells. Given the unobservable nature of the inputs, including plugging costs and useful lives, the initial measurement of the ARO liability is deemed to use Level 3 inputs. See Note 7—Asset Retirement Obligations for further discussion of the Partnership’s asset retirement obligations.

The fair value of the Operating Company’s revolving credit facility approximates its carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.

16. LEASES

The Partnership leases certain compression assets and other equipment.

The Partnership adopted ASC Topic 842 on January 1, 2019 using the optional transition method of adoption. The Partnership elected a package of practical expedients that together allows an entity to not reassess (i) whether a contract is or contains a lease, (ii) lease classification and (iii) initial direct costs. In addition, the Partnership elected the following practical expedients: (i) to not reassess certain land easements; (ii) to not apply the recognition requirements under the standard to short-term leases; (iii) to not reassess lease terms for lease terms on leases entered into prior to the effective date of adoption and (iv) lessor accounting policy election to exclude lessor costs paid directly by the lessee.

For leases where the Partnership is the lessee, the Partnership recorded a total of $1.2 million in right-of-use assets and corresponding new lease liabilities on its Consolidated Balance Sheet representing the present value of its future operating lease payments. Adoption of the standard did not require an adjustment to the opening balance of retained earnings. The discount rate used to determine present value was based on the rate of interest that the Partnership estimated it would have to pay to borrow (on a collateralized-basis over a similar term) an amount equal to the lease payments in a similar economic environment as of January 1, 2019. The Partnership is required to reassess the discount rate for any new and modified lease contracts as of the lease effective date.

The right-of-use assets and lease liabilities recognized upon adoption of ASC Topic 842 were based on the lease classifications, lease commitment amounts and terms recognized under the prior lease accounting guidance. Leases with an initial term of twelve months or less are considered short-term leases and are not recorded on the balance sheet.

The following table summarizes operating lease costs for the year ended December 31, 2019:



	Year Ended December 31, 2019
	(In thousands)
Operating lease costs	$	1,890

For the year ended December 31, 2019, cash paid for operating lease liabilities, and reported in cash flows provided by operating activities on the Partnership’s Statement of Consolidated Cash Flows, was $1.9 million. During the year ended December 31, 2019, the Partnership recorded an additional $0.9 million of right-of-use assets in exchange for new lease liabilities.

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Notes to Consolidated Financial Statements - (Continued)

The operating lease right-of-use assets were reported on the Consolidated Balance Sheet. As of December 31, 2019, the operating right-of-use assets were $0.4 million and the operating lease liabilities were $0.4 million, of which $0.4 million was classified as current. As of December 31, 2019, the weighted average remaining lease term was 0.5 years and the weighted average discount rate was 8.4%.

Schedule of Operating Lease Liability Maturities

The following table summarizes undiscounted cash flows owed by the Partnership to lessors pursuant to contractual agreements in effect as of December 31, 2019:



	As of December 31, 2019
	(In thousands)
2020	$	426
2021	—
2022	—
2023	—
2024	—
Thereafter	—
Total lease payments	426
Less: interest	8
Present value of lease liabilities	$	418

For leases in which the Partnership is the lessor, the Partnership (i) retained classification of its historical leases as the Partnership is not required to reassess classification upon adoption of the new standard, (ii) expensed indirect leasing costs in connection with new or extended tenant leases, the recognition of which would have been deferred under prior accounting guidance and (iii) aggregated revenue from its lease components and non-lease components (comprised of tenant expense reimbursements) into revenue from rental properties.

17. COMMITMENTS AND CONTINGENCIES

As of December 31, 2019, the Partnership’s anticipated future capital commitments for its equity method investments total $169.9 million in aggregate.

18. SUBSEQUENT EVENTS

Cash Distribution

On February 13, 2020, the board of directors of the General Partner approved a cash distribution for the fourth quarter of 2019 of $0.29 per common unit, payable on March 10, 2020, to unitholders of record at the close of business on March 3, 2020.

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Notes to Consolidated Financial Statements - (Continued)

19. REPORT OF OPERATING BUSINESS SEGMENTS

The Partnership’s operations are located in the United States and are reported in two operating business segments: (i) midstream services and (ii) real estate operations. The segments comprise the structure used by its Chief Operating Decision Maker (“CODM”) to make key operating decisions and assess performance. The following tables summarize the results of the Partnership’s operating business segments during the periods presented:



	Year Ended December 31, 2019
	Midstream Services		Real Estate Operations		Total
	(In thousands)
Revenues—related party	$	409,120	$	—	$	409,120
Revenues—third party	24,324		—		24,324
Rental income—related party	—		4,771		4,771
Rental income—third party	—		7,890		7,890
Other real estate income—related party	—		379		379
Other real estate income—third party	—		1,189		1,189
Total revenues	433,444		14,229		447,673
Direct operating expenses	106,311		—		106,311
Cost of goods sold (exclusive of depreciation and amortization)	62,856		—		62,856
Real estate operating expenses	—		2,643		2,643
Loss on disposal of property, plant and equipment	1,524		—		1,524
Depreciation, amortization and accretion	34,775		7,561		42,336
Loss from equity method investments	6,329		—		6,329
Segment profit	221,649		4,025		225,674
General and administrative expenses					(12,663		)
Interest expense, net					(1,039		)
Net income before income taxes	221,649		4,025		211,972
Provision for income taxes					26,253
Net income	$	221,649	$	4,025	$	185,719

Segment assets	$	1,435,659	$	108,239	$	1,636,393

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Notes to Consolidated Financial Statements - (Continued)



	Year Ended December 31, 2018
	Midstream Services		Real Estate Operations		Total
	(In thousands)
Revenues—related party	$	169,396	$	—	$	169,396
Revenues—third party	3,292		—		3,292
Rental income—related party	—		2,383		2,383
Rental income—third party	—		8,125		8,125
Other real estate income—related party	—		228		228
Other real estate income—third party	—		1,043		1,043
Total revenues	172,688		11,779		184,467
Direct operating expenses	33,714		—		33,714
Cost of goods sold (exclusive of depreciation and amortization)	38,852		—		38,852
Real estate operating expenses	—		1,872		1,872
Loss on disposal of property, plant and equipment	2,577		—		2,577
Depreciation, amortization and accretion	18,088		7,046		25,134
Segment profit	79,457		2,861		82,318
General and administrative expenses					(1,999		)
Net income before income taxes	79,457		2,861		80,319
Provision for income taxes					17,359
Net income	$	79,457	$	2,861	$	62,960

Segment assets	$	456,997	$	104,923	$	604,017

20. QUARTERLY FINANCIAL DATA (Unaudited)



	2019
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands, except per unit amounts)
Revenues	$	95,176	$	111,774	$	115,415	$	125,308
Income from operations	50,138		55,602		52,558		61,042
Income tax expense	10,832		8,724		3,294		3,403
Net income after taxes	39,356		46,679		48,080		51,604
Net income before initial public offering	39,356		26,639		—		—
Net income subsequent to initial public offering	—		20,040		48,080		51,604
Net income attributable to non-controlling interest subsequent to initial public offering	—		15,237		36,549		39,136
Net income (loss) attributable to Rattler Midstream LP	$	—	$	4,803	$	11,531	$	12,468
Net income (loss) attributable to limited partners per common unit:
Basic	$	—	$	0.11	$	0.26	$	0.27
Diluted	$	—	$	0.11	$	0.26	$	0.27

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Notes to Consolidated Financial Statements - (Continued)



	2018
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In thousands)
Revenues	$	33,875	$	49,788	$	49,301	$	51,503
Income from operations	17,070		21,020		22,672		19,557
Income tax expense	4,133		4,089		4,892		4,245
Net income after taxes	$	14,396	$	15,472	$	17,780	$	15,312

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