ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
We provide crude oil, natural gas and water-related midstream services (including fresh water sourcing and transportation and saltwaterproduced water gathering and disposal) to Diamondback under long-term, fixed-fee contracts. As of June 30, 2019, the assets Diamondback has contributed to us include 814 miles of pipeline across the Midland and Delaware Basins with approximately 236,000 Bbl/d of crude oil gathering capacity, 80,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering capacity, 2.829 MMBbl/d of SWD capacity and 575,000 Bbl/d of fresh water gathering capacity. In addition to theour midstream infrastructure assets, that Diamondback contributed to us, we own equity interests in twothree 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 growthdevelopment 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 SWDproduced water disposal capabilities.
Sources of Our IncomeRevenues
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; fresh 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 Fivestones 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 fresh 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 saltwater gathering and disposal system spans approximately 414 miles and consists of gathering pipelines along with SWD wells and facilities which collectively gather and dispose of saltwater from operations throughout Diamondback’s Permian acreage.
We have entered into multiplecurrently generate a substantial portion of our revenues under 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 on certain dedicated acreage in the Delaware and Midland Basins. Our agreements include substantial acreage dedications. Please read “Business—Our Acreage Dedication” 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.
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. Please read “Risk Factors—Risks Related to Our Business—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” and “Risk Factors—Risks Related to Our Business—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” 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.
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. Please read “Business—Our Commercial Agreements with Diamondback” 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.
Recent Acquisitions
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 SWD 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 fresh 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 fresh water sourcing when drilling. All 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 SWD 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 assets contributed have estimated remaining useful lives of 30 years.
Diamondback funded and our Predecessor acquired a 10% equity interest in each of the EPIC and Gray Oak projects, long-haul crude oil pipelines under development that we expect, following commencement of operations, will provide us with a steady, oil-weighted cash flow stream. These pipelines will also provide Diamondback with long-term long-haul transportation capacity for a portion of its Delaware and Midland Basin crude oil production. These pipelines will provide Diamondback a total takeaway capacity of up to 200,000 Bbl/d.
2019 Highlights
Significant Operating Results
The following are the significant operating results for the three months ended June 30, 2019 as compared with the three months ended June 30, 2018:
average crude oil gathering volumes of 78,066 Bbl/d, an increase of 82% year over year;
average natural gas gathering volumes of 84,426 MMBtu/d, an increase of 154% year over year;
average produced water gathered volumes of 770,091 Bbl/d, an increase of 256% year over year; and
average fresh water delivered volumes of 447,823 Bbl/d, and increase of 104% year over year.
Operational Update
As of June 30, 2019, we have a total of 814 miles of pipelines across the Midland and Delaware Basins with a total of approximately 236,000 Bbl/d of crude oil gathering capacity, 80,000 Mcf/d of natural gas compression capability, 150,000 Mcf/d of natural gas gathering capacity, 2.829 MMBbl/d of SWD capacity and 575,000 Bbl/d of fresh water gathering capacity, all 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.
Pipeline Infrastructure Assets
The following tables provide information regarding our gathering, compression and transportation system as of June 30, 2019 and utilization for the quarter ended June 30, 2019:
|
| | | | | | | | |
| (miles) | Delaware Basin | | Midland Basin | | Permian Total |
| Crude oil | 99 |
| | 43 |
| | 142 |
|
| Natural gas | 143 |
| | — |
| | 143 |
|
| SWD | 239 |
| | 195 |
| | 434 |
|
| Fresh water | 26 |
| | 69 |
| | 95 |
|
| Total | 507 |
| | 307 |
| | 814 |
|
|
| | | | | | | | | | | |
| (capacity/capability) | Delaware Basin | | Midland Basin | | Permian Total | | Utilization |
| Crude oil (Bbl/d) | 180,000 |
| | 56,000 |
| | 236,000 |
| | 33 | % |
| Natural gas compression (Mcf/d) | 80,000 |
| | — |
| | 80,000 |
| | 85 | % |
| Natural gas pipeline (Mcf/d) | 150,000 |
| | — |
| | 150,000 |
| | 46 | % |
| SWD (Bbl/d) | 1,367,000 |
| | 1,462,000 |
| | 2,829,000 |
| | 27 | % |
| Fresh water (Bbl/d) | 120,000 |
| | 455,000 |
| | 575,000 |
| | 78 | % |
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. The following table summarizes throughput and crude oil sales volumes for the three and six months ended June 30, 2019 and 2018:
|
| | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| (throughput) | 2019 | | 2018 | | 2019 | | 2018 |
| Crude oil gathering volumes (Bbl/d) | 78,066 |
| | 42,945 |
| | 76,326 |
| | 36,715 |
|
| Natural gas gathering volumes (MMBtu/d) | 84,426 |
| | 33,189 |
| | 72,546 |
| | 31,827 |
|
| Saltwater services volumes (Bbl/d) | 770,091 |
| | 216,193 |
| | 740,807 |
| | 228,744 |
|
| Fresh water services volumes (Bbl/d) | 447,823 |
| | 220,021 |
| | 400,476 |
| | 263,062 |
|
Principal Components of Our Cost Structure
General and Administrative
In connection with the closing of the IPO, we entered into the Services and Secondment Agreement with Diamondback under which we will pay fees to Diamondback with respect to certain operational services Diamondback will provide in support of our operations. The 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.
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 the 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 three and six months ended June 30, 2019, we accrued $31,814 for Texas margin tax payable pursuant to the Tax Sharing Agreement with Diamondback.
Other income (expense)
Interest income
This represents the interest received on our cash and cash equivalents.
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.
Expense from equity investments
This represents our proportional expense from our equity 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 SWD 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 unrelated third parties. These assets included five SWD 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 Fresh Water Assets located within the Permian Basin. These assets included numerous fresh water wells and 28 hydraulic fracturing ponds, located across nine fresh water transportation systems, that had previously been used to store and transport fresh water for Diamondback’s drilling operations. All of the 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 gas and produced water pipelines, SWD 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 SWD 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 fresh 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 fresh water sourcing when drilling. All 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 SWD 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 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 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 Investments
On February 1, 2019, Diamondback funded and our Predecessor acquired a 10% equity interest in the EPIC project and on February 15, 2019, Diamondback funded and our Predecessor acquired a 10% equity interest in the Gray Oak project.
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 real estate assets were contributed by Diamondback effective January 31, 2018 and we earn revenue from these assets through various lease agreements.
Operating Expenses
In connection with 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, we expect that there will be differences in the results of our operations between our Predecessor’s historical financial statements and our future 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 the Partnership Agreement and the Services and Secondment Agreement.
We anticipate incurring approximately $1.4 million annually of incremental general and administrative expenses attributable to being a publicly traded partnership, which includes 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 anticipate incurring under the Services and Secondment Agreement are not reflected in our historical financial statements.
Financing
There are differences in the way we will 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 new 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 effective date of our election to be treated as a corporation. As such, our net income for the three and six months ended June 30, 2019 reflects a provision for income taxes for the period subsequent to our IPO. For the periods prior to our IPO, net income for the three and six months ended June 30, 2019 and 2018 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.
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. We expect these contracts to 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, commodityCommodity 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 fresh 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 growthdevelopment 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. Please read “Business—Regulation 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. 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. For more information, see “Business—Regulation 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.
Results of Operations for the Three Months Ended June 30, 2019 and 2018
The following table sets forth selected historical operating data for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, 2019 | | Three Months Ended June 30, 2018 |
| | Midstream Services | | Real Estate Operations | | Total | | Midstream Services | | Real Estate Operations | | Total |
| Operating Results: | (In thousands) |
| Revenues: | | | | | | | | | | | |
| Total revenues | $ | 108,144 |
| | $ | 3,630 |
| | $ | 111,774 |
| | $ | 46,741 |
| | $ | 3,047 |
| | $ | 49,788 |
|
| Costs and expenses: | | | | | | | | | | | |
| Direct operating expenses | 26,406 |
| | — |
| | 26,406 |
| | 10,992 |
| | — |
| | 10,992 |
|
| Cost of goods sold (exclusive of depreciation and amortization shown below) | 15,849 |
| | — |
| | 15,849 |
| | 8,267 |
| | — |
| | 8,267 |
|
| Real estate operating expenses | — |
| | 695 |
| | 695 |
| | — |
| | 540 |
| | 540 |
|
| Depreciation, amortization and accretion | 8,235 |
| | 1,923 |
| | 10,158 |
| | 4,044 |
| | 1,931 |
| | 5,975 |
|
| General and administrative expenses | | | | | 3,068 |
| | | | | | 426 |
|
| (Gain) loss on sale of property, plant and equipment | | | | | (4 | ) | | | | | | 2,568 |
|
| Total costs and expenses | 50,490 |
| | 2,618 |
| | 56,172 |
| | 23,303 |
| | 2,471 |
| | 28,768 |
|
| Income from operations | 57,654 |
| | 1,012 |
| | 55,602 |
| | 23,438 |
| | 576 |
| | 21,020 |
|
| Other income (expense): | | | | | | | | | | | |
| Interest expense, net | | | | | (85 | ) | | | | | | — |
|
| Expense from equity investments | | | | | (114 | ) | | | | | | (1,459 | ) |
| Total other expense | | | | | (199 | ) | | | | | | (1,459 | ) |
| Net income before income taxes | 57,654 |
| | 1,012 |
| | 55,403 |
| | 23,438 |
| | 576 |
| | 19,561 |
|
| Provision for income taxes | | | | | 8,724 |
| | | | | | 4,089 |
|
| Net income after taxes | $ | 57,654 |
| | $ | 1,012 |
| | $ | 46,679 |
| | $ | 23,438 |
| | $ | 576 |
| | $ | 15,472 |
|
| | | | | | | | | | | | |
| Net income before initial public offering | | | | | $ | 26,639 |
| | | | | | |
| | | | | | | | | | | | |
| Net income subsequent to initial public offering | | | | | $ | 20,040 |
| | | | | | |
| Net income attributable to non-controlling interest subsequent to initial public offering | | | | | 15,237 |
| | | | | | |
| Net income attributable to Rattler Midstream LP | $ | 57,654 |
| | $ | 1,012 |
| | $ | 4,803 |
| | | | | | |
Comparison of the Three Months Ended June 30, 20192021 and 20182020 and Six Months Ended June 30, 2021 and 2020
Revenues.
Revenues increased by $62.0$12.4 million or 124%, to $111.8$101.1 million for the three months ended June 30, 20192021 from $49.8$88.7 million for the three months ended June 30, 2018. This increase was2020, primarily due to increasedan increase in sourced water, produced water and gas volumes. The increase in these volumes stems from an overall recovery in Diamondback’s drilling and production activities after curtailments in the second quarter of 2020 in response to the COVID-19 pandemic and other economic factors.
Revenues decreased by $18.2 million to $199.9 million for the six months ended June 30, 2021 from $218.1 million for the six months ended June 30, 2020. This decrease relates primarily to a reduction in sourced water, produced water and oil volumes due to Diamondback’s lower level of drilling and completion activity in first quarter of 2021. In addition, the February 2021 winter storms in the Permian Basin caused the further loss of approximately four to five days of Diamondback’s total net production. This decrease was partially offset by an increase in gas volumes largely due to the contributioncontinued build out of certain crude oil gathering, SWD wells and land and buildingsmidstream assets that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us, on January 1, 2019, as well as the additional build out of historical Partnership systems.
Direct Operating Expense. Expenses
Direct operating expense was $26.3 million and $58.8 million for the three and six months ended June 30, 2021, respectively, compared to $37.4 million and $70.3 million for the three and six months ended June 30, 2020. The decreases in the 2021 periods compared to the 2020 periods are largely due to a focus on cost cutting efforts along with a reduction in expenses related to declining volumes in 2021.
Cost of Goods Sold
Cost of goods sold (exclusive of depreciation and amortization) increased by $15.4$5.6 million or 140%, to $26.4$10.3 million for the three months ended June 30, 20192021 from $11.0 million for three months ended June 30, 2018. This increase was primarily due to increased volumes largely due to the contribution of certain crude oil gathering, SWD wells and land and buildings that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us on January 1, 2019, as well as the additional build out of historical Partnership systems.
Cost of Goods Sold. Cost of goods sold expense increased by $7.6 million, or 92%, to $15.8$4.7 million for the three months ended June 30, 2019 from $8.3 million for the three months ended June 30, 2018. The increase relates to the increased build out of historical fresh water systems of the Operating Company.
Real Estate Operating Expenses. Real estate operating expense increased by $0.2 million, or 29%, to $0.7 million for the three months ended June 30, 2019 from $0.5 million for the three months ended June 30, 2018.2020. The increase primarily relates to the addition of new tenants.
Depreciation, Amortization and Accretion. Depreciation, amortization and accretion expense increased by $4.2 million, or 70%, to $10.2 million for the three months ended June 30, 2019 from $6.0 million for the three months ended June 30, 2018. This increase was primarilyhigher sourced water volumes due to asset contributions fromDiamondback’s increased level of drilling and completion activity in the second quarter of 2021 compared to the second quarter of 2020 during which Diamondback curtailed a portion of its drilling and further development of existing gathering, transportation and disposal systems.completion activity.
GeneralCost of goods sold (exclusive of depreciation and Administrative Expense. General and administrative expense increasedamortization) decreased by $2.6$1.6 million to $3.1 million for the three months ended June 30, 2019 from $0.4 million for the three months ended June 30, 2018. This increase was primarily due to increased shared service allocations and additional professional service fees due to business growth and the contribution of additional midstream assets.
Expense from Equity Investments. Expense from equity investments decreased by $1.3 million, or 92%, from$1.5 million for the three months ended June 30, 2018 to $0.1 million for the three months ended June 30, 2019. The expense from equity investments for the three months ended June 30, 2019 was due to interest expense incurred on Gray Oak's promissory note. The expense from equity investments for the three months ended June 30, 2018 was due to the de-recognition of income from HMW LLC, which we no longer recognize as an equity investment.
(Gain) loss on Sale of Property, Plant and Equipment. Loss on sale of property, plant and equipment was $2.6 million for the three months ended June 30, 2018, and was due to the exchange of interest in SWD assets.
Provision for Income Taxes. We recorded income tax expense of $8.7 million and $4.1 million for the three months ended June 30, 2019 and 2018, respectively. The change in our income tax provision was primarily due to an increase in pre-tax income for the three months ended June 30, 2019, partially offset by the impact of net income attributable to non-controlling interest for the 2019 period subsequent to our IPO. Total income tax expense for the three months ended June 30, 2019 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest.
Results of Operations for the Six Months Ended June 30, 2019 and 2018
The following table sets forth selected historical operating data for the periods indicated:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30, 2019 | | Six Months Ended June 30, 2018 |
| | Midstream Services | | Real Estate Operations | | Total | | Midstream Services | | Real Estate Operations | | Total |
| Operating Results: | (In thousands) |
| Revenues: | | | | | | | | | | | |
| Total revenues | $ | 200,207 |
| | $ | 6,743 |
| | $ | 206,950 |
| | $ | 78,162 |
| | $ | 5,501 |
| | $ | 83,663 |
|
| Costs and expenses: | | | | | | | | | | | |
| Direct operating expenses | 46,592 |
| | — |
| | 46,592 |
| | 16,198 |
| | — |
| | 16,198 |
|
| Cost of goods sold (exclusive of depreciation and amortization shown below) | 28,902 |
| | — |
| | 28,902 |
| | 13,518 |
| | — |
| | 13,518 |
|
| Real estate operating expenses | — |
| | 1,221 |
| | 1,221 |
| | — |
| | 818 |
| | 818 |
|
| Depreciation, amortization and accretion | 16,193 |
| | 3,869 |
| | 20,062 |
| | 8,588 |
| | 3,203 |
| | 11,791 |
|
| General and administrative expenses | | | | | 4,437 |
| | | | | | 680 |
|
| (Gain) loss on sale of property, plant and equipment | | | | | (4 | ) | | | | | | 2,568 |
|
| Total costs and expenses | 91,687 |
| | 5,090 |
| | 101,210 |
| | 38,304 |
| | 4,021 |
| | 45,573 |
|
| Income from operations | 108,520 |
| | 1,653 |
| | 105,740 |
| | 39,858 |
| | 1,480 |
| | 38,090 |
|
| Other income (expense): | | | | | | | | | | | |
| Interest expense, net | | | | | (85 | ) | | | | | | — |
|
| Expense from equity investments | | | | | (64 | ) | | | | | | — |
|
| Total other expense | | | | | (149 | ) | | | | | | — |
|
| Net income before income taxes | 108,520 |
| | 1,653 |
| | 105,591 |
| | 39,858 |
| | 1,480 |
| | 38,090 |
|
| Provision for income taxes | | | | | 19,556 |
| | | | | | 8,222 |
|
| Net income after taxes | $ | 108,520 |
| | $ | 1,653 |
| | $ | 86,035 |
| | $ | 39,858 |
| | $ | 1,480 |
| | $ | 29,868 |
|
| | | | | | | | | | | | |
| Net income before initial public offering | | | | | $ | 65,995 |
| | | | | | |
| | | | | | | | | | | | |
| Net income subsequent to initial public offering | | | | | $ | 20,040 |
| | | | | | |
| Net income attributable to non-controlling interest subsequent to initial public offering | | | | | 15,237 |
| | | | | | |
| Net income attributable to Rattler Midstream LP | $ | 108,520 |
| | $ | 1,653 |
| | $ | 4,803 |
| | | | | | |
Comparison of the Six Months Ended June 30, 2019 and 2018
Revenues. Revenues increased by $123.3 million, or 147%, to $207.0$19.1 million for the six months ended June 30, 20192021 from $83.7$20.7 million for the six months ended June 30, 2018. This increase2020. The decrease primarily relates to increaseda reduction in sourced water volumes largely due to Diamondback’s lower level of drilling and completion activity in the contributionfirst quarter of certain crude oil gathering, SWD wells2021, which was partially offset by an increased level of drilling and land and buildings that Diamondback acquired pursuant tocompletion activity in the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us on January 1, 2019,second quarter of 2021 as well as the additional build out of historical Partnership systems.discussed above.
Interest Expense, Net
Direct Operating Expense.
Direct operating
Net interest expense increased by $30.4was $8.2 million or 188%, to $46.6and $15.5 million for the three and six months ended June 30, 2019 from $16.22021, respectively, compared to $1.9 million and $4.5 million for the three and six months ended June 30, 2018. This increase was primarily due to increased volumes largely due2020, respectively. The increases in the 2021 periods compared to the contribution2020 periods primarily relate to interest accrued on the Notes which were issued in July 2020 and bear interest at a rate of certain crude oil gathering, SWD wells and land and buildings that Diamondback acquired pursuant to the Ajax acquisition and the Energen acquisition, which Diamondback contributed to us5.625% per annum.
Gain (loss) on January 1, 2019, as well as the additional build outSale of historical Partnership systems.Equity Method Investments
CostThe $23.0 million gain on sale of Goods Sold. Cost of goods sold expense increased by $15.4 million, or 114%, to $28.9 millionequity method investments for the three and six months ended June 30, 20192021 related to the sale of our interest in Amarillo Rattler. See Note 4 —Divestitures included in the condensed notes to the consolidated financial statements included elsewhere in this report for discussion of the sale.
Income (loss) from $13.5Equity Method Investments
Income from equity method investments was $4.5 million and $1.6 million for the three and six months ended June 30, 2018. The increase relates2021, respectively, compared to the increased build outlosses of historical fresh water systems of the Operating Company.
Real Estate Operating Expenses. Real estate operating expense increased by $0.4$13.0 million or 49%, to $1.2and $13.3 million for the three and six months ended June 30, 2019 from $0.8 million for2020, respectively. The loss in the six months ended June 30, 2018. The increase2020 periods primarily relatesrelated to a proportional charge of impairment recorded by the investee associated with its goodwill. See Note 7 — Equity Method Investments included in the condensed notes to the addition of new tenants.consolidated financial statements included elsewhere in this report for additional discussion.
Non-GAAP Financial Measures
Depreciation, Amortization and Accretion
. Depreciation, amortization and accretion expense increased by $8.3 million, or 70%, to $20.1 million for the six months ended June 30, 2019 from $11.8 million for the six months ended June 30, 2018. This increase was primarily due to asset contributions from Diamondback and further development of existing gathering, transportation and disposal systems.
General and Administrative Expense. General and administrative expense increased by $3.8 million to $4.4 million for the six months ended June 30, 2019 from $0.7 million for the six months ended June 30, 2018. This increase was primarily due to increased shared service allocations and additional professional service fees due to business growth and the contribution of additional midstream assets.
Expense from Equity Investments. Expense from equity investments was $0.1 million for the six months ended June 30, 2019, and was related to interest expense incurred on Gray Oak's promissory note. There was no income or expense from equity investments for the six months ended June 30, 2018.
(Gain) loss on Sale of Property, Plant and Equipment. Loss on sale of property, plant and equipment was $2.6 million for the six months ended June 30, 2018, and was due to the exchange of interest in SWD assets.
Provision for Income Taxes. We recorded income tax expense of $19.6 million and $8.2 million for the six months ended June 30, 2019 and 2018, respectively. The change in our income tax provision was primarily due to an increase in pre-tax income for the six months ended June 30, 2019, partially offset by the impact of net income attributable to non-controlling interest for the 2019 period subsequent to our IPO. Total income tax expense for the six months ended June 30, 2019 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest.
Adjusted EBITDA
Adjusted EBITDA is a supplemental non-GAAP financial measure used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations period to period without regard to our financing methods or capital structure.
We define Adjusted EBITDA as net income before(loss) attributable to Rattler Midstream LP plus net income taxes,(loss) attributable to non-controlling interest before interest expense net(net of amount capitalized, interest expense related to equity investments, non-cash unit-based compensation expense and depreciation, amortization and accretion. Depreciation, amortization and accretion includescapitalized), depreciation, amortization and accretion on assets and liabilities of the Operating Company, in addition toour proportional depreciation amortization and accretion on our equity investments. Interestinterest expense related to equity method investments, represents our proportional impairments and abandonments related to equity method investments, non-cash unit-based compensation expense, impairment and abandonments, (gain) loss on disposal of assets, (gain) loss from sale of equity method investment, provision for income (loss) from equity investments plus interest on that amount.taxes and other. The GAAP measure most directly comparable to Adjusted EBITDA is net income. income (loss). However, Adjusted EBITDA is not a measure of net income (loss) as determined by GAAP. We exclude the items listed above from net income (loss) in arriving at Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as historic costs of depreciable assets.
Adjusted EBITDA should not be considered an alternative to net income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computation of Adjusted EBITDA excludes some, but not all, items that affect net income (loss), 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.
The following table presents a reconciliation of Adjusted EBITDA to net income the most directly comparable GAAP financial measuresto Adjusted EBITDA for each of the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2021 | | 2020 | | 2021 | | 2020 |
| (In thousands) |
| Reconciliation of Net Income (Loss) to Adjusted EBITDA: | | | | | | | |
| Net income (loss) attributable to Rattler Midstream LP | $ | 12,445 | | | $ | 2,822 | | | $ | 18,460 | | | $ | 15,853 | |
| Net income (loss) attributable to non-controlling interest | 42,032 | | | 9,640 | | | 61,925 | | | 51,197 | |
| Net income (loss) | 54,477 | | | 12,462 | | | 80,385 | | | 67,050 | |
| Interest expense, net of amount capitalized | 8,235 | | | 1,926 | | | 15,545 | | | 4,547 | |
| Depreciation, amortization and accretion | 15,239 | | | 12,100 | | | 26,485 | | | 24,606 | |
| Depreciation and interest expense related to equity method investments | 10,036 | | | 7,244 | | | 20,561 | | | 11,010 | |
| Impairments and abandonments related to equity method investments | — | | | 15,839 | | | 2,933 | | | 15,839 | |
| Non-cash unit-based compensation expense | 2,485 | | | 2,120 | | | 4,817 | | | 4,339 | |
| Impairment and abandonments | — | | | — | | | 3,371 | | | — | |
| (Gain) loss on disposal of assets | 5,005 | | | 1,243 | | | 5,011 | | | 2,781 | |
| Gain (loss) on sale of equity method investments | (22,989) | | | — | | | (22,989) | | | — | |
| Provision for income taxes | 3,539 | | | 1,083 | | | 5,210 | | | 4,903 | |
| Other | 22 | | | (138) | | | 34 | | | (216) | |
| Adjusted EBITDA | 76,049 | | | 53,879 | | | 141,363 | | | 134,859 | |
| Less: Adjusted EBITDA attributable to non-controlling interest | 55,084 | | | 38,288 | | | 102,219 | | | 95,912 | |
| Adjusted EBITDA attributable to Rattler Midstream LP | $ | 20,965 | | | $ | 15,591 | | | $ | 39,144 | | | $ | 38,947 | |
|
| | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2019 | 2018 | | 2019 | 2018 |
| | (In thousands) |
| Reconciliation of net income to Adjusted EBITDA: | | | | | |
| Net income | $ | 46,679 |
| $ | 15,472 |
| | $ | 86,035 |
| $ | 29,868 |
|
| Depreciation, amortization and accretion | 10,158 |
| 5,975 |
| | 20,062 |
| 11,791 |
|
| Interest expense, net of amount capitalized | 85 |
| — |
| | 85 |
| — |
|
| Interest expense related to equity investments | 149 |
| — |
| | 149 |
| — |
|
| Non-cash unit-based compensation expense | 831 |
| — |
| | 831 |
| — |
|
| Provision for income taxes | 8,724 |
| 4,089 |
| | 19,556 |
| 8,222 |
|
| Adjusted EBITDA | 66,626 |
| $ | 25,536 |
| | 126,718 |
| $ | 49,881 |
|
| Less: Adjusted EBITDA prior to the Offering | (40,651 | ) | | | (100,743 | ) | |
| Adjusted EBITDA subsequent to the Offering | 25,975 |
| | | 25,975 |
| |
| Less: Adjusted EBITDA attributable to non-controlling interest | (18,483 | ) | | | (18,483 | ) | |
| Adjusted EBITDA attributable to Rattler Midstream LP | $ | 7,492 |
| | | $ | 7,492 |
| |
Liquidity and Capital Resources
Liquidity and Financing Arrangements
Our sources of liquidly and capital resources are provided by operating cash flow, cash on hand, borrowings under our revolving credit facility, and capital market transactions. We believe the combination of these capital resources will be sufficient to meet our working capital requirements, expected quarterly cash distributions and fund our operations through year-end 2019.
Historically, ourOur primary sources of liquidity were based on cash flow from operations and funding from Diamondback.
We do not have any commitment from Diamondback or 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. Our sources of liquidity following the IPO includebeen cash generated from operations, borrowings under our new revolving credit facilitythe Credit Agreement and if necessary, the issuance of additional equity or debt securities.the Notes. 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. Should we require additional capital, the indirect effect of volatile commodity markets and/or adverse macroeconomic conditions may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all.
Cash Distributions on Common Units
On August 2, 2021, the board of directors of our general partner approved a cash distribution for the second quarter of 2021 of $0.25 per common unit, payable on August 23, 2021, to common unitholders of record at the close of business on August 16, 2021. The board of directors of our General Partner adopted a cashgeneral partner may change the distribution policy pursuantat any time and from time to which we will distribute $0.25 per common unit within 60 days after the end of each quarter, beginning with the quarter ending September 30, 2019, subject to applicable lawtime. See Note 10 —Unitholders’ Equity and our obligations under certain contractual agreements. Please read “Cash Distribution Policy and Restrictions on Distributions" Distributionsincluded in the condensed notes to the consolidated financial statements included elsewhere in this report for additional discussion of 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.distribution policy.
Cash Flows
The following table presents our cash flows for the periods indicated:
| | | | | | | | | | | |
| | Six Months Ended June 30, |
| | 2021 | | 2020 |
| | (In thousands) |
| Cash Flow Data: | | | |
| Net cash provided by (used in) operating activities | $ | 128,412 | | | $ | 131,864 | |
| Net cash provided by (used in) investing activities | 17,763 | | | (139,707) | |
| Net cash provided by (used in) financing activities | (152,552) | | | 8,380 | |
| Net increase (decrease) in cash | $ | (6,377) | | | $ | 537 | |
Operating Activities
Net cash provided by operating activities investing activities and financing activities for the six months ended June 30, 2019 and 2018 were as follows:
|
| | | | | | | |
| | Six Months Ended June 30, |
| | 2019 | | 2018 |
| | (In thousands) |
| Cash Flow Data: | | | |
| Net cash provided by operating activities | $ | 139,397 |
| | $ | 89,141 |
|
| Net cash used in investing activities | (140,337 | ) | | (84,671 | ) |
| Net cash used in financing activities | (3,887 | ) | | — |
|
| Net increase (decrease) in cash | $ | (4,827 | ) | | $ | 4,470 |
|
Operating Activities
Net cash provideddecreased by
operating activities increased by $50.3$3.5 million during the six months ended June 30,
20192021 compared to the six months ended June 30,
2018. The increase was2020, due
to increased operations as additional assets have been placed into service and the contribution of certain crude oil gathering, SWD wells and land and buildings that Diamondback acquired pursuantprimarily to the
Ajax acquisition$18.2 million decline in revenues and
an increase in cash paid for interest of $9.2 million. These decreases were partially offset by reductions of $11.5 million in direct operating expenses and $1.6 million in cost of goods sold, and distributions representing returns on investment from our equity method investments of $9.1 million. The remaining decrease stems from largely offsetting changes in working capital due primarily to the
Energen acquisition, which Diamondback contributedtiming of when collections are made on accounts receivable and payments are made on accounts payable and accrued liabilities. See — Results of Operations for further discussion of changes in revenue, operating expenses and interest expense and Note 7 — Equity Method Investments included in the condensed notes to us on January 1, 2019.the consolidated financial statements included elsewhere in this report for further discussion of distributions.
Investing Activities
Net cash provided by investing activities was $17.8 million during the six months ended June 30, 2021, and primarily consists of $23.5 million of proceeds from the sale of our Amarillo Rattler equity method investment, $9.1 million in proceeds from the sale of a real estate asset, and $9.1 million in distributions considered to be returns of investment received from our equity method investments. These proceeds were partially offset by capital expenditures for property, plant and equipment of $17.7 million and contributions to our equity method investments of $6.5 million, which continue to decrease as discussed in —Recent Developments.
Net cash used in investing activities was $140.3 million and $84.7$139.7 million during the six months ended June 30, 2019 and 2018, respectively,2020, and primarily related to additions to property, plant and equipment and contributions to our EPIC andequity method investments, which were partially offset by distributions considered to be returns of investment received from our Gray Oak and OMOG equity method investments. See Note 9—Equity Method Investments.
Financing Activities
Net cash used in financing activities was $3.9$152.6 million during the six months ended June 30, 2019,2021, and primarily related to (i) distributions of $59.6 million to our unitholders, (ii) net proceeds frompayments on the credit facility of $74.0 million as we continue to reduce our IPOborrowings and (iii) $16.3 million in repurchases of common units under our repurchase program during the period.
Net cash provided by financing activities was $8.4 million during the six months ended June 30, 2020, and primarily related to proceeds from borrowings on the Operating Company’s revolving credit facility of $719.6 million, a contribution of $1.0 million from our General Partner for its general partner interest in the Partnership, a contribution of $1.0 million from Diamondback for its Class B units and borrowings, net of repayment of $1.0$99.0 million, partially offset by distributions to our unitholders of $726.5$88.0 million during the period. There was no net
Common Unit Repurchase Program
On October 29, 2020, the board of directors of our general partner approved a common unit repurchase program to acquire up to $100 million of our outstanding common units. The common unit repurchase program is authorized to extend through December 31, 2021 and we intend to purchase common units under the repurchase program opportunistically with cash providedon hand and free cash flow from operations. The repurchase program may be suspended from time to time, modified, extended or discontinued by or used in financing activities duringthe board of directors of our general partner at any time. During the six months ended June 30, 2018.2021, we repurchased approximately $16.3 million of common units under the repurchase program. As of June 30, 2021, $68.9 million remained available for use to repurchase common units under our program.
Capital Requirements and Sources of Liquidity
The midstream energy business is capital intensive, requiring the maintenance of existing gathering systems and other midstream assets and facilities and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. However, with respect to capital expenditures incurred for acquisitions or capital improvements, we have some discretion and control. In times of reduced operational activity, we may choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity and prioritize capital projects that we believe have the highest expected returns and potential to generate near-term cash flow. Subject to financing alternatives, we may also increase our capital expenditures significantly to take advantage of opportunities we consider to be attractive. We consistently monitor and may adjust our projected capital expenditures in response to factors both within and outside our control.
For the six months ended June 30, 2021, our total capital expenditures were $17.7 million, which primarily consisted of $13.9 million related to produced water disposal assets, $1.2 million related to crude oil gathering assets, $1.3 million related to natural gas gathering assets, and $1.2 million related to real estate assets. We estimate that our total capital expenditures related to midstream assets for 20192021 will be between $225.0$30 million and $250.0$50 million, excluding our anticipated total capital commitments associated withrelated to our equity interest in certain pipeline projects. Formethod investments of approximately $5 million to $15 million. We also estimate that distributions from our equity method investments will be between $35 million to $45 million. However, this range could decrease due to the six months ended June 30, 2019, our total capital expenditures were $102.9 million,continued impact, either directly or indirectly, of which $43.9 million were related to SWD assets, $21.1 million were related tothe COVID-19 pandemic or volatile crude oil gathering assets, $16.1 million were relatedprices on our business.
We own equity interests in the EPIC, Gray Oak, Wink to natural gas gathering assets, $21.2 million were related to fresh water assetsWebster and $0.6 million were related to other assetsOMOG joint ventures. Each of these joint ventures is accounted for using the equity method. The following table sets forth our cumulative capital contributions and liabilities.anticipated future capital commitment for each of our equity method investment interests:
| | | | | | | | | | | | | | | | | | | | | | | |
| Ownership Interest | | Acquisition Date | | Cumulative Capital Contributions to Date | | Anticipated Future Capital Commitment |
| | | | | (In thousands) |
| EPIC Crude Holdings, LP | 10 | % | | February 1, 2019 | | $ | 137,534 | | | $ | 2,466 | |
| Gray Oak Pipeline, LLC | 10 | % | | February 15, 2019 | | $ | 142,096 | | | $ | — | |
| Wink to Webster Pipeline LLC | 4 | % | | July 30, 2019 | | $ | 87,389 | | | $ | 20,611 | |
| OMOG JV LLC | 60 | % | | October 1, 2019 | | $ | 218,555 | | | $ | — | |
As of June 30, 2019, our anticipated future capital commitments for2021, we anticipate making additional contributions of $5.9 million to our equity method investments includes $57.9 million forduring the remainder of 2019 and totals $161.1 million2021. For further discussion regarding these investments see Note 7 — Equity Method Investment included in aggregate. With respectthe condensed notes to the Wink to Webster Pipeline, which we joined as a member on July 30, 2019, we expect capital contributions for the balance of 2019 to be less than $20 million.consolidated financial statements included elsewhere in this report.
Based upon current expectations for 2019,2021, we believe that our cash flowflows from operations, cash on hand and borrowing under our revolving credit facility will be sufficient to fund our operations and anticipated future capital commitments through year-end 2019.the 12-month period following the filing of this report and thereafter.
Credit Agreement—Wells FargoIndebtedness
We, as parent,At June 30, 2021, we have $505.0 million in principal amount of outstanding indebtedness, which consists of Notes and borrowings under the Operating Company,Company’s revolving credit facility as borrower, entered into a credit agreement, dated May 28, 2019, with Wells Fargo Bank, National Association, as administrative agent, and a syndicatediscussed further below.
The Operating Company’s Revolving Credit AgreementFacility
The Operating Company’s credit agreement provides for a revolving credit facility in the maximum credit amount of $600 million. Loan principal may be optionally repaid from time$600.0 million, which is expandable to time without premium or penalty (other than$1.0 billion upon our election, subject to obtaining additional lender commitments and satisfaction of 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 City, and is secured by substantially all of our, the Operating Company and Tall City's assets.conditions. As of June 30, 2019, we had $1.02021, there was $5.0 million of outstanding borrowings, and $599.0$595.0 million available for future borrowings, under the Credit Agreement.
Operating Company’s revolving credit facility. The outstandingweighted average interest rate on borrowings under the Credit Agreement bear interest at a per annum rate elected by Rattler LLC that is based onwas 1.36% and 1.39% for 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 loansthree 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 commencing with the fiscal quarter ending September 30, 2019 | 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) commencing with the fiscal quarter ending September 30, 2019 | Not less than 2.50 to 1.00 |
For purposes of calculating the financial maintenance covenants prior to the fiscal quarter endingsix months ended June 30, 2020, EBITDA (as defined in the Credit Agreement) will be annualized based2021, respectively. The credit agreement matures on the actual EBITDA for the preceding fiscal quarters starting with the fiscal quarter ending September 30, 2019.May 28, 2024.
As of June 30, 2019, we were2021, the Operating Company was in compliance with all financial covenants under theits Credit Agreement. The lenders may accelerate all
Notes Offering
On July 14, 2020, we completed an offering of our 5.625% senior notes due 2025 in the aggregate principal amount of $500.0 million. We received net proceeds of approximately $489.5 million from the notes offering. We loaned the gross proceeds of $500.0 million of the indebtednessnotes offering to the Operating Company, which used the proceeds from the notes offering to repay then outstanding borrowings under its revolving credit facility. Interest on the Credit Agreement uponnotes is payable semi-annually, and 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.first interest payment was made on January 15, 2021.
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 ofFor additional information regarding the outstanding loans or commitmentsdebt, see Note 8—Debt included in the condensed notes to lend.the consolidated financial statements included elsewhere in this report.Contractual Obligations
As of June 30, 2019, exceptExcept as may be discussed in Note 8—Debt and Note 15—Commitments and Contingencies included in the condensed notes to the consolidated financial statements included elsewhere in this report, there were no material changes to our contractual obligations and other commitments, from those disclosed in our Annual Report on Form 10-K for the capital commitments and capital contributions described above and the operating leases described in Note 17—Leases, we did not have any material contractual obligations.year ended December 31, 2020.
Critical Accounting Policies
There have been no changes in our critical accounting policies from those disclosed in our final prospectus dated May 22, 2019 and filed withAnnual Report on Form 10-K for the SEC pursuant to Rule 424(b) under the Securities Act on May 24, 2019.year ended December 31, 2020.
Off-Balance Sheet Arrangements
We currently have no significant off-balance sheet arrangements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Commodity Price Risk
We currently generate the majority of our revenues pursuant to fee-based agreements with Diamondback under which we are paid based on volumetric fees, rather than the underlying value of the commodity. Consequently, our existing operations and cash flowflows have little direct exposure to commodity price risk. However, Diamondback and our other customers are exposed to commodity price risk, and extended reduction in commodity prices could reduce the production volumes available for our midstream services in the future below expected levels. Although we intend to maintain fee-based pricing terms on both new contracts and existing contracts for which prices have not yet been set, our efforts to negotiate such terms may not be successful, which could have a materially adverse effect on our business.
We may acquire or develop additional midstream assets in a manner that increases our exposure to commodity price risk. Future exposure to the volatility of crude oil, natural gas and natural gas liquids prices could have a material adverse effect on our business, financial condition, results of operations, cash flows and ability to make cash distributions to our unitholders.
Credit Risk
We are subject to counterparty credit risk related to our midstream commercial contracts, lease agreements and joint venture receivables. We derive substantially all of our revenue from our commercial agreements with Diamondback, 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.Diamondback. As a result, we are subjectdirectly affected by changes to theDiamondback’s business related to 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 natural gas liquids 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 with respect to our commercial agreements.otherwise. We cannot predict the extent to which Diamondback’s businessesbusiness 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 acreageprogram or to perform under our commercial agreements. Any material non-payment or non-performanceWhile 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 Diamondback under our commercial agreements would have a counterparty could result in 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 dedication under certain circumstances. Any temporary or permanent release of volumes or acreage from the acreage dedication could materially adversely affect our business, financial condition, results of operations, cash flow and ability to make cash distributions. For more information, see “Business-Our Commercial Agreements with Diamondback” 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.
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.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our revolvingthe Operating Company’s credit facility.agreement. The terms of our revolving credit facilitythe 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 June 30, 2019,2021, we had $1.0$5.0 million of outstanding borrowings and $599.0$595.0 million available for future borrowings under its revolving credit facility. An increase or decrease of 1% in the Credit Agreement. During the three and six months ended June 30, 2021, the weighted average interest rate would have a corresponding decrease or increase in our interest expenseon borrowings under the Credit Agreement was 1.36% and 1.39%, respectively.
ITEM 4. 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,general partner, we have established disclosure controls and procedures, as defined in RuleRules 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,general partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of June 30, 2019,2021, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner,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 Partnergeneral partner have concluded that as of June 30, 2019,2021, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the six monthsquarter ended June 30, 20192021 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Due to the nature of our business, we are,may be involved in various routine legal proceedings, disputes and claims from time to time involvedarising in routine litigation or subject to disputes or claims related tothe ordinary course of our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us,there are currently no such matters that, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations.operations or cash flows. See Note 15—Commitments and Contingencies included in the condensed notes to the consolidated financial statements included elsewhere in this report.
ITEM 1A. RISK FACTORS
Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
None.
Issuer Repurchases of Equity Securities
Our common unit repurchase activity for the three months ended June 30, 2021 was as follows:
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| Period | | Total Number of Units Purchased(1) | | Average Price Paid Per Unit (2) | | Total Number of Units Purchased as Part of Publicly Announced Plan | | Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan (3) |
| | ($ in thousands, except per unit amounts) |
| | | | | | | | |
| | | | | | | | |
| | | | | | | | |
| April 1, 2021 - April 30, 2021 | | 315,000 | | $ | 10.97 | | | 315,000 | | $ | 70,688 | |
| May 1, 2021 - May 31, 2021 | | 318,186 | | $ | 10.79 | | | 160,000 | | $ | 68,947 | |
| June 1, 2021 - June 30, 2021 | | — | | | $ | — | | | — | | | $ | 68,947 | |
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| Total | | 633,186 | | $ | 10.88 | | | 475,000 | | |
(1)Includes common units repurchased from employees in order to Rule 424(b) on May 24, 2019.
satisfy tax withholding requirements. Such units are retired immediately upon repurchase.
(2)The average price paid per common unit is net of any commissions paid to repurchase common units.
(3)In October 2020, the board of directors of our general partner approved a common unit repurchase program to acquire up to $100 million of our outstanding common units through December 31, 2021. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of our general partner at any time.
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| Exhibit Number | | Description |
3.1 | | |
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| 3.1 | | |
| 3.2 | | |
| 3.3 | | |
4.13.4 | | |
| 3.5 | | |
| 3.6 | | |
| 3.7 | | |
10.13.8 | | |
| 3.9 | | |
10.24.1 | | Credit Agreement,Indenture, dated May 28, 2019, by andas of July 14, 2020, among Rattler Midstream LP, as issuer, Rattler Midstream Operating LLC, Tall City Towers LLC, Rattler OMOG LLC and Rattler Ajax Processing LLC, as borrower, Rattler Midstream LP, as parent,guarantors, and Wells Fargo Bank, National Association, as trustee (including the administrative agent, and certain lenders from time to time party theretoform of Rattler Midstream LP’s 5.625% Senior Notes due 2025) (incorporated by reference to Exhibit 10.24.1 of the Partnership’sRegistrant’s Current Report on Form 8-K (File 001-38919) filed on May 29, 2019)July 14, 2020). |
10.3# | | |
10.4# | | |
10.5 | | |
10.6 | | |
10.7 | | |
10.8#
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31.1* | | |
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| 31.1* | | |
| 31.2* | | |
| 32.1** | | |
101.INS*101 | | The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021, formatted in Inline XBRL Instance Document. The instance document does not appearXBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statements of Comprehensive Income, (iv) Condensed Consolidated Statement of Changes in the interactive data file because its XBRL tags are embedded within the inline XBRL document.Unitholders’ Equity, (v) Condensed Consolidated Statements of Cash Flows and (vi) Condensed Notes to Consolidated Financial Statements. |
101.SCH*104 | | Inline XBRL Taxonomy Extension Schema Document. |
101.CAL* | | Inline XBRL Taxonomy Extension Calculation Linkbase. |
101.DEF* | | Inline XBRL Taxonomy Extension Definition Linkbase Document. |
101.LAB* | | Inline XBRL Taxonomy Extension Labels Linkbase Document. |
101.PRE* | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. |
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Exhibit Number | | Description |
104 | | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). |
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| * | Filed herewith. |
| ** | The certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q 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. |
# | Management contract, compensatory plan or arrangement. |
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SIGNATURES
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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| | RATTLER MIDSTREAM LP |
| | |
| | By: | RATTLER MIDSTREAM GP LLC, |
| | | its general partner |
| | | |
| Date: | August 5, 2021 | RATTLER MIDSTREAM LP |
| By: | | |
| | By: | RATTLER MIDSTREAM GP LLC, |
| | | its general partner |
| | | |
Date: | August 8, 2019 | By: | /s/ Travis D. Stice |
| | | Travis D. Stice |
| | | Chief Executive Officer |
| | | (Principal Executive Officer) |
| | |
| Date: | August 8, 20195, 2021 | By: | /s/ Teresa L. Dick |
| | | Teresa L. Dick |
| | | Chief Financial Officer |
| | | (Principal Financial Officer) |