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Viper Energy Partners LP, a Subsidiary of Diamondback Energy, Inc., Reports Third Quarter 2021 Financial and Operating Results
THIRD QUARTER HIGHLIGHTS
- Q3 2021 average production of 16,087 bo/d (27,620 boe/d)
- Q3 2021 consolidated net income (including non-controlling interest) of
$73.4 million ; net income attributable toViper Energy Partners LP of$16.8 million , or$0.26 per common unit - Adjusted net income (as defined and reconciled below) of
$57.7 million , or$0.90 per common unit - Q3 2021 cash distribution of
$0.38 per common unit, representing approximately 70% of total cash available for distribution of$0.54 per common unit;$0.38 distribution is up 15% quarter over quarter and implies a 6.9% annualized yield based on theOctober 29, 2021 unit closing price of$22.05 - Consolidated adjusted EBITDA (as defined and reconciled below) of
$92.6 million and cash available for distribution to Viper’s common units (as reconciled below) of$34.3 million - Repurchased 765,512 common units in Q3 2021 for an aggregate of
$13 .7 million - Ended the third quarter of 2021 with total long-term debt of
$571.9 and net debt of$530.4 million (as defined and reconciled below) - 223 total gross (3.1 net 100% royalty interest) horizontal wells turned to production on Viper’s acreage during Q3 2021 with an average lateral length of 10,163 feet
- As previously announced, closed acquisition from
Swallowtail Royalties LLC andSwallowtail Royalties II LLC ; adds approximately 2,313 net royalty acres in theNorthern Midland Basin , roughly 62% of which are operated by Diamondback - Initiating average daily production guidance for Q4 2021 and Q1 2022 of 17,000 to 17,750 bo/d (28,250 to 29,500 boe/d)
- Increasing full year 2021 average daily production guidance to 16,250 to 16,500 bo/d (27,250 to 27,750 boe/d)
- As of
October 11, 2021 , there were approximately 570 gross horizontal wells in the process of active development on Viper’s acreage in which Viper expects to own an average 1.7% net royalty interest (9.5 net 100% royalty interest wells) - Approximately 492 gross (9.3 net 100% royalty interest) line-of-sight wells on Viper’s acreage that are not currently in the process of active development, but for which Viper has visibility to the potential of future development in coming quarters, based on Diamondback’s current completion schedule and third party operators’ permits
- Approximately 60% of distributions paid in 2021 are reasonably estimated to constitute non-taxable reductions to the tax basis, and not dividends, for
U.S. federal income tax purposes
“During the third quarter, Viper saw third party operated net wells turned to production on our acreage rebound to their highest level since the first quarter of 2020. As a result of our continued strong production, and further enhanced by our high-margin exposure to increasing commodity prices, Viper’s cash available for distribution increased 15% quarter over quarter to
FINANCIAL UPDATE
Viper’s third quarter 2021 average unhedged realized prices were
During the third quarter of 2021, the Company recorded total operating income of
As of
THIRD QUARTER 2021 CASH DISTRIBUTION & CAPITAL RETURN PROGRAM
The Board of Directors of Viper’s
On
During the third quarter of 2021, Viper repurchased 765,512 common units for an aggregate of
OPERATIONS AND ACQUISITIONS UPDATE
During the third quarter of 2021, Viper estimates that 223 gross (3.1 net 100% royalty interest) horizontal wells with an average royalty interest of 1.4% were turned to production on its existing acreage position with an average lateral length of 10,163 feet. Of these 223 gross wells, Diamondback is the operator of 44 gross wells with an average royalty interest of 4.0%, and the remaining 179 gross wells, with an average royalty interest of 0.7%, are operated by third parties.
During the third quarter of 2021, Viper acquired 38 net royalty acres for an aggregate purchase price of approximately
Subsequent to the end of the third quarter, Viper completed the acquisition of certain mineral and royalty interests from
The mineral and royalty interests acquired in the Swallowtail acquisition represent approximately 2,313 net royalty acres primarily in the
The following table summarizes Viper’s gross well information:
Diamondback Operated | Third Party Operated | Total | ||||||
Horizontal wells turned to production (third quarter 2021)(1): | ||||||||
Gross wells | 44 | 179 | 223 | |||||
Net 100% royalty interest wells | 1.8 | 1.3 | 3.1 | |||||
Average percent net royalty interest | 4.0 | % | 0.7 | % | 1.4 | % | ||
Horizontal producing well count (as of |
||||||||
Gross wells | 1,295 | 4,282 | 5,577 | |||||
Net 100% royalty interest wells | 97.7 | 58.4 | 156.1 | |||||
Average percent net royalty interest | 7.5 | % | 1.4 | % | 2.8 | % | ||
Horizontal active development well count (as of |
||||||||
Gross wells | 103 | 467 | 570 | |||||
Net 100% royalty interest wells | 5.8 | 3.7 | 9.5 | |||||
Average percent net royalty interest | 5.7 | % | 0.8 | % | 1.7 | % | ||
Line of sight wells (as of |
||||||||
Gross wells | 107 | 385 | 492 | |||||
Net 100% royalty interest wells | 5.7 | 3.6 | 9.3 | |||||
Average percent net royalty interest | 5.3 | % | 0.9 | % | 1.9 | % |
(1) | Average lateral length of 10,163 feet. |
There continues to be active development across Viper’s asset base with near-term activity expected to be driven primarily by Diamondback operations. The 570 gross wells currently in the process of active development are those wells that have been spud and are expected to be turned to production within approximately the next six to eight months. Further in regard to the active development on Viper’s asset base, there are currently 35 gross rigs operating on Viper’s acreage, five of which are operated by Diamondback. The 492 line-of-sight wells are those that are not currently in the process of active development, but for which Viper has reason to believe that they will be turned to production within approximately the next 15 to 18 months. The expected timing of these line-of-sight wells is based primarily on permitting by third party operators or Diamondback’s current expected completion schedule. Existing permits or active development of Viper’s royalty acreage does not ensure that those wells will be turned to production.
GUIDANCE UPDATE
Below is Viper’s updated guidance for the full year 2021, as well as average production guidance for the fourth quarter of 2021 and first quarter of 2022.
Q4 2021 / Q1 2022 Net Production - MBo/d | 17.00 - 17.75 |
Q4 2021 / Q1 2022 Net Production - MBoe/d | 28.25 - 29.50 |
Full Year 2021 Net Production - MBo/d | 16.25 - 16.50 |
Full Year 2021 Net Production - MBoe/d | 27.25 - 27.75 |
Unit costs ($/boe) | |
Depletion | |
Cash G&A | |
Non-Cash Unit-Based Compensation | |
Interest Expense(1) | |
Production and Ad Valorem Taxes (% of Revenue) (2) | 7% |
(1) | Includes actual interest expense for the first three quarters of 2021 plus expected interest for the remainder of 2021 assuming |
(2) | Includes production taxes of 4.6% for crude oil and 7.5% for natural gas and natural gas liquids and ad valorem taxes. |
CONFERENCE CALL
Viper will host a conference call and webcast for investors and analysts to discuss its results for the third quarter of 2021 on
About
Viper is a limited partnership formed by Diamondback to own, acquire and exploit oil and natural gas properties in
About
Diamondback is an independent oil and natural gas company headquartered in
Forward-Looking Statements
This news release contains forward-looking statements within the meaning of the federal securities laws. All statements, other than historical facts, that address activities that Viper assumes, plans, expects, believes, intends or anticipates (and other similar expressions) will, should or may occur in the future are forward-looking statements. The forward-looking statements are based on management’s current beliefs, based on currently available information, as to the outcome and timing of future events, including specifically the statements regarding the current volatile industry and macroeconomic conditions, volatile commodity prices, production levels on properties in which Viper has mineral and royalty interests, governmental actions on environmental policies and regulations impacting Viper and its operators, severe weather conditions, any acquisitions or dispositions, Diamondback’s plans for developing Viper’s acreage discussed above, development activity by other operators, Viper’s cash distribution policy and the impact of the COVID-19 pandemic. These forward-looking statements involve certain risks and uncertainties that could cause the results to differ materially from those expected by the management of Viper. Information concerning these risks and other factors can be found in Viper’s filings with the
Consolidated Balance Sheets | |||||||
(unaudited, in thousands, except unit amounts) | |||||||
2021 | 2020 | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 41,515 | $ | 19,121 | |||
Royalty income receivable (net of allowance for credit losses) | 47,133 | 32,210 | |||||
Royalty income receivable—related party | 22,022 | 1,998 | |||||
Other current assets | 654 | 665 | |||||
Total current assets | 111,324 | 53,994 | |||||
Property: | |||||||
Oil and natural gas interests, full cost method of accounting ( |
2,902,270 | 2,895,542 | |||||
Land | 5,688 | 5,688 | |||||
Accumulated depletion and impairment | (570,406 | ) | (496,176 | ) | |||
Property, net | 2,337,552 | 2,405,054 | |||||
Funds held in escrow | 30,025 | — | |||||
Other assets | 3,567 | 2,327 | |||||
Total assets | $ | 2,482,468 | $ | 2,461,375 | |||
Liabilities and Unitholders’ Equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 208 | $ | 43 | |||
Accrued liabilities | 26,000 | 18,262 | |||||
Derivative instruments | 35,357 | 26,593 | |||||
Total current liabilities | 61,565 | 44,898 | |||||
Long-term debt, net | 564,452 | 555,644 | |||||
Derivative instruments | 697 | — | |||||
Total liabilities | 626,714 | 600,542 | |||||
Commitments and contingencies | |||||||
Unitholders’ equity: | |||||||
General partner | 749 | 809 | |||||
Common units (63,830,715 units issued and outstanding as of |
580,992 | 633,415 | |||||
Class B units (90,709,946 units issued and outstanding |
956 | 1,031 | |||||
582,697 | 635,255 | ||||||
Non-controlling interest | 1,273,057 | 1,225,578 | |||||
Total equity | 1,855,754 | 1,860,833 | |||||
Total liabilities and unitholders’ equity | $ | 2,482,468 | $ | 2,461,375 |
Consolidated Statements of Operations | |||||||||||||||
(unaudited, in thousands, except per unit data) | |||||||||||||||
Three Months Ended |
Nine Months Ended |
||||||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||||||
Operating income: | |||||||||||||||
Royalty income | $ | 127,649 | $ | 62,584 | $ | 337,619 | $ | 171,857 | |||||||
Lease bonus income | 223 | 40 | 1,032 | 1,685 | |||||||||||
Other operating income | 132 | 318 | 479 | 761 | |||||||||||
Total operating income | 128,004 | 62,942 | 339,130 | 174,303 | |||||||||||
Costs and expenses: | |||||||||||||||
Production and ad valorem taxes | 8,625 | 5,049 | 23,426 | 14,306 | |||||||||||
Depletion | 25,366 | 24,780 | 74,230 | 72,204 | |||||||||||
General and administrative expenses | 1,735 | 1,811 | 6,118 | 6,160 | |||||||||||
Total costs and expenses | 35,726 | 31,640 | 103,774 | 92,670 | |||||||||||
Income (loss) from operations | 92,278 | 31,302 | 235,356 | 81,633 | |||||||||||
Other income (expense): | |||||||||||||||
Interest expense, net | (8,328 | ) | (8,238 | ) | (24,161 | ) | (24,870 | ) | |||||||
Gain (loss) on derivative instruments, net | (9,599 | ) | (5,084 | ) | (70,649 | ) | (47,469 | ) | |||||||
Gain (loss) on revaluation of investment | — | (1,984 | ) | — | (8,661 | ) | |||||||||
Other income, net | — | 188 | 77 | 1,111 | |||||||||||
Total other expense, net | (17,927 | ) | (15,118 | ) | (94,733 | ) | (79,889 | ) | |||||||
Income (loss) before income taxes | 74,351 | 16,184 | 140,623 | 1,744 | |||||||||||
Provision for (benefit from) income taxes | 906 | — | 941 | 142,466 | |||||||||||
Net income (loss) | 73,445 | 16,184 | 139,682 | (140,722 | ) | ||||||||||
Net income (loss) attributable to non-controlling interest | 56,613 | 16,948 | 121,208 | 23,963 | |||||||||||
Net income (loss) attributable to |
$ | 16,832 | $ | (764 | ) | $ | 18,474 | $ | (164,685 | ) | |||||
Net income (loss) attributable to common limited partner units: | |||||||||||||||
Basic | $ | 0.26 | $ | (0.01 | ) | $ | 0.29 | $ | (2.43 | ) | |||||
Diluted | $ | 0.26 | $ | (0.01 | ) | $ | 0.29 | $ | (2.43 | ) | |||||
Weighted average number of common limited partner units outstanding: | |||||||||||||||
Basic | 64,152 | 67,847 | 64,724 | 67,832 | |||||||||||
Diluted | 64,241 | 67,847 | 64,815 | 67,832 |
Consolidated Statements of Cash Flows | |||||||||||||||
(unaudited, in thousands) | |||||||||||||||
Three Months Ended |
Nine Months Ended |
||||||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||||||
Cash flows from operating activities: | |||||||||||||||
Net income (loss) | $ | 73,445 | $ | 16,184 | $ | 139,682 | $ | (140,722 | ) | ||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||
Deferred income tax expense (benefit) | — | — | — | 142,466 | |||||||||||
Depletion | 25,366 | 24,780 | 74,230 | 72,204 | |||||||||||
(Gain) loss on derivative instruments, net | 9,599 | 5,084 | 70,649 | 47,469 | |||||||||||
Net cash receipts (payments) on derivatives | (25,306 | ) | (16,164 | ) | (61,188 | ) | (18,718 | ) | |||||||
(Gain) loss on revaluation of investment | — | 1,984 | — | 8,661 | |||||||||||
Other | 1,340 | 873 | 3,332 | 2,681 | |||||||||||
Changes in operating assets and liabilities: | |||||||||||||||
Royalty income receivable | (5,122 | ) | 10 | (14,923 | ) | 25,981 | |||||||||
Royalty income receivable—related party | (18,343 | ) | (13,994 | ) | (20,024 | ) | (4,335 | ) | |||||||
Other | 9,013 | 8,586 | 7,914 | 7,519 | |||||||||||
Net cash provided by (used in) operating activities | 69,992 | 27,343 | 199,672 | 143,206 | |||||||||||
Cash flows from investing activities: | |||||||||||||||
Acquisitions of oil and natural gas interests | (5,909 | ) | 764 | (6,728 | ) | (64,508 | ) | ||||||||
Other | — | 7,360 | — | 7,360 | |||||||||||
Net cash provided by (used in) investing activities | (5,909 | ) | 8,124 | (6,728 | ) | (57,148 | ) | ||||||||
Cash flows from financing activities: | |||||||||||||||
Proceeds from borrowings under credit facility | 62,000 | 3,000 | 87,000 | 95,000 | |||||||||||
Repayment on credit facility | (32,000 | ) | (30,000 | ) | (79,000 | ) | (65,000 | ) | |||||||
Repayment of senior notes | — | (5,910 | ) | — | (19,697 | ) | |||||||||
Repurchased units as part of unit buyback | (13,740 | ) | — | (33,562 | ) | — | |||||||||
Distributions to public | (20,995 | ) | (2,015 | ) | (46,102 | ) | (38,943 | ) | |||||||
Distributions to Diamondback | (30,201 | ) | (2,764 | ) | (65,913 | ) | (53,112 | ) | |||||||
Other | (29 | ) | (67 | ) | (2,948 | ) | (534 | ) | |||||||
Net cash provided by (used in) financing activities | (34,965 | ) | (37,756 | ) | (140,525 | ) | (82,286 | ) | |||||||
Net increase (decrease) in cash and cash equivalents | 29,118 | (2,289 | ) | 52,419 | 3,772 | ||||||||||
Cash, cash equivalents and restricted cash at beginning of period | 42,422 | 9,663 | 19,121 | 3,602 | |||||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 71,540 | $ | 7,374 | $ | 71,540 | $ | 7,374 |
Selected Operating Data | |||||||||||
(unaudited) | |||||||||||
Three Months Ended |
Three Months Ended |
Three Months Ended |
|||||||||
Production Data: | |||||||||||
Oil (MBbls) | 1,480 | 1,503 | 1,456 | ||||||||
Natural gas (MMcf) | 3,347 | 3,219 | 3,111 | ||||||||
Natural gas liquids (MBbls) | 503 | 449 | 455 | ||||||||
Combined volumes (MBOE)(1) | 2,541 | 2,489 | 2,430 | ||||||||
Average daily oil volumes (BO/d) | 16,087 | 16,516 | 15,829 | ||||||||
Average daily combined volumes (BOE/d) | 27,620 | 27,352 | 26,409 | ||||||||
Average sales prices: | |||||||||||
Oil ($/Bbl) | $ | 67.67 | $ | 62.51 | $ | 36.80 | |||||
Natural gas ($/Mcf) | $ | 3.61 | $ | 2.96 | $ | 1.07 | |||||
Natural gas liquids ($/Bbl) | $ | 30.66 | $ | 22.21 | $ | 12.44 | |||||
Combined ($/BOE)(2) | $ | 50.24 | $ | 45.58 | $ | 25.76 | |||||
Oil, hedged ($/Bbl)(3) | $ | 50.57 | $ | 48.58 | $ | 27.65 | |||||
Natural gas, hedged ($/Mcf)(3) | $ | 3.61 | $ | 2.96 | $ | 0.16 | |||||
Natural gas liquids ($/Bbl)(3) | $ | 30.66 | $ | 22.21 | $ | 12.44 | |||||
Combined price, hedged ($/BOE)(3) | $ | 40.28 | $ | 37.18 | $ | 19.11 | |||||
Average Costs ($/BOE): | |||||||||||
Production and ad valorem taxes | $ | 3.39 | $ | 3.28 | $ | 2.08 | |||||
General and administrative - cash component(4) | 0.59 | 0.73 | 0.63 | ||||||||
Total operating expense - cash | $ | 3.98 | $ | 4.01 | $ | 2.71 | |||||
General and administrative - non-cash unit compensation expense | $ | 0.10 | $ | 0.14 | $ | 0.11 | |||||
Interest expense, net | $ | 3.28 | $ | 3.20 | $ | 3.39 | |||||
Depletion | $ | 9.98 | $ | 9.63 | $ | 10.20 |
(1) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. |
(2) | Realized price net of all deducts for gathering, transportation and processing. |
(3) | Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices. |
(4) | Excludes non-cash unit-based compensation expense for the respective periods presented. |
NON-GAAP FINANCIAL MEASURES
Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies. Viper defines Adjusted EBITDA as net income (loss) attributable to
Viper defines cash available for distribution generally as an amount equal to its Adjusted EBITDA for the applicable quarter less cash needed for income taxes payable, debt service, contractual obligations, fixed charges and reserves for future operating or capital needs that the board of directors of Viper’s general partner may deem appropriate, cash paid for tax withholding on vested common units, distribution equivalent rights and preferred distributions, if any. Management believes cash available for distribution is useful because it allows them to more effectively evaluate Viper’s operating performance excluding the impact of non-cash financial items and short-term changes in working capital. Viper’s computations of Adjusted EBITDA and cash available for distribution may not be comparable to other similarly titled measures of other companies or to such measure in its credit facility or any of its other contracts.
The following tables present a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measures of Adjusted EBITDA and cash available for distribution:
(unaudited, in thousands, except per unit data) | |||
Three Months Ended |
|||
Net income (loss) attributable to |
$ | 16,832 | |
Net income (loss) attributable to non-controlling interest | 56,613 | ||
Net income (loss) | 73,445 | ||
Interest expense, net | 8,328 | ||
Non-cash unit-based compensation expense | 243 | ||
Depletion | 25,366 | ||
Non-cash (gain) loss on derivative instruments | (15,707 | ) | |
Provision for (benefit from) income taxes | 906 | ||
Consolidated Adjusted EBITDA | 92,581 | ||
Less: Adjusted EBITDA attributable to non-controlling interest(1) | 54,269 | ||
Adjusted EBITDA attributable to |
$ | 38,312 | |
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: | |||
Income taxes payable | $ | (906 | ) |
Debt service, contractual obligations, fixed charges and reserves | (2,996 | ) | |
Distribution equivalent rights payments | (62 | ) | |
Preferred distributions | (45 | ) | |
Cash available for distribution to |
$ | 34,303 | |
Common limited partner units outstanding | 63,831 | ||
Cash available for distribution per limited partner unit | $ | 0.54 | |
Cash per unit approved for distribution | $ | 0.38 |
(1) | Does not take into account special income allocation consideration. |
Adjusted net income (loss) is a non-GAAP financial measure equal to net income (loss) attributable to
The following table presents a reconciliation of net income (loss) attributable to
Adjusted Net Income (Loss) | |||||||
(unaudited, in thousands, except per unit data) | |||||||
Three Months Ended |
|||||||
Amounts | Amounts Per Diluted Unit | ||||||
Net income (loss) attributable to |
$ | 16,832 | $ | 0.26 | |||
Net income (loss) attributable to non-controlling interest | 56,613 | 0.88 | |||||
Net income (loss) | 73,445 | 1.14 | |||||
Non-cash (gain) loss on derivative instruments, net | (15,707 | ) | (0.24 | ) | |||
Adjusted net income (loss) | 57,738 | 0.90 | |||||
Less: Adjusted net income (loss) attributed to non-controlling interests | 43,962 | 0.69 | |||||
Adjusted net income (loss) attributable to |
$ | 13,776 | $ | 0.21 | |||
Weighted average common units outstanding: | |||||||
Basic | 64,152 | ||||||
Diluted | 64,241 | ||||||
RECONCILIATION OF LONG-TERM DEBT TO NET DEBT
The Company defines net debt as debt (excluding debt issuance, discounts and premiums) less cash equivalents. Net debt should not be considered an alternative to, or more meaningful than, total debt, the most directly comparable GAAP measure. Management uses net debt to determine the Company's outstanding debt obligations that would not be readily satisfied by its cash and cash equivalents on hand. The Company believes this metric is useful to analysts and investors in determining the Company's leverage position because the Company has the ability to, and may decide to, use a portion of its cash and cash equivalents to reduce debt.
2021 |
Net Q3 Principal Borrowings/(Repayments) | 2021 |
2021 |
2020 |
2020 |
||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Total long-term debt(1) | $ | 571,938 | $ | 30,000 | $ | 541,938 | $ | 536,938 | $ | 563,938 | $ | 606,438 | |||||||||||
Cash and cash equivalents | (41,515 | ) | (42,422 | ) | (11,727 | ) | (19,121 | ) | (7,374 | ) | |||||||||||||
Net debt | $ | 530,423 | $ | 499,516 | $ | 525,211 | $ | 544,817 | $ | 599,064 |
(1) | Excludes debt issuance, discounts & premiums. |
Derivatives
As of the filing date, the Company had the following outstanding derivative contracts. The Company’s derivative contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on New York Mercantile Exchange West Texas Intermediate pricing and Crude Oil Brent. When aggregating multiple contracts, the weighted average contract price is disclosed.
Crude Oil (Bbls/day, $/Bbl) | |||||||||||
Q4 2021 | Q1 2022 | Q2 2022 | |||||||||
Collars - WTI ( |
10,000 | 2,500 | 2,000 | ||||||||
Floor Price | $ | 30.00 | $ | 45.00 | $ | 45.00 | |||||
Ceiling Price | $ | 43.05 | $ | 79.55 | $ | 80.15 | |||||
Deferred Premium Puts - WTI ( |
— | 9,500 | 8,000 | ||||||||
Strike | $ | — | $ | 47.51 | $ | 47.50 | |||||
Premium | $ | — | $ | (1.57 | ) | $ | (1.55 | ) |
Natural Gas (Mmbtu/day, $/Mmbtu) | |||||||||||||||
Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022 | ||||||||||||
Costless Collars - |
20,000 | 20,000 | 20,000 | 20,000 | |||||||||||
Floor Price | $ | 2.50 | $ | 2.50 | $ | 2.50 | $ | 2.50 | |||||||
Ceiling Price | $ | 4.62 | $ | 4.62 | $ | 4.62 | $ | 4.62 | |||||||
Investor Contacts:
+1 432.221.7467
alawlis@viperenergy.com
+1 432.221.7420
agilfillian@viperenergy.com
Source:
Source: Viper Energy Partners LP