PRESS RELEASES
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Viper Energy Partners LP, A Subsidiary of Diamondback Energy, Inc., Reports First Quarter 2021 Financial and Operating Results
FIRST QUARTER HIGHLIGHTS
- Previously announced Q1 2021 average production of 15,500 bo/d (26,066 boe/d)
- Q1 2021 cash distribution of
$0.25 per common unit, representing approximately 60% of cash available for distribution;$0.42 per unit of cash available for distribution implies a 9.3% annualized distributable cash flow yield based on theApril 30, 2021 unit closing price of$18.01 - Q1 2021 consolidated net income (including non-controlling interest) of
$23.9 million ; adjusted net income (as defined and reconciled below) of$40.4 million - Consolidated adjusted EBITDA (as defined and reconciled below) of
$73.5 million and cash available for distribution to Viper’s common units (as reconciled below) of$27.6 million - Repurchased 869,965 common units in Q1 2021 for an aggregate of
$13 .0 million - Ended the first quarter of 2021 with net debt of
$525.2 million (as defined and reconciled below); total debt down$136.6 million sinceMarch 31, 2020 , or an approximately 20% reduction over the past twelve months - 134 total gross (2.5 net 100% royalty interest) horizontal wells turned to production on Viper’s acreage during Q1 2021 with an average lateral length of 10,584 feet
- Initiating average daily production guidance for Q2 2021 and Q3 2021 of 15,000 to 16,000 bo/d (25,000 to 26,500 boe/d)
- Increasing full year 2021 average daily production guidance to 15,000 to 16,250 bo/d (25,000 to 27,000 boe/d)
- As of
April 12, 2021 , there were approximately 471 gross horizontal wells in the process of active development on Viper’s acreage, in which Viper expects to own an average 1.8% net royalty interest (8.7 net 100% royalty interest wells) - Approximately 490 gross (8.7 net 100% royalty interest) line-of-sight wells 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
- Q4 2020 and Q1 2021 distributions reasonably estimated to not constitute dividends for
U.S. federal income tax purposes; instead should generally constitute non-taxable reductions to the tax basis
“Viper produced a strong first quarter with both production and realized pricing exceeding expectations and, as a result, generated almost
FINANCIAL UPDATE
Viper’s first quarter 2021 average unhedged realized prices were
During the first quarter of 2021, the Company recorded total operating income of
As of
FIRST QUARTER 2021 CASH DISTRIBUTION & CAPITAL RETURN PROGRAM
The Board of Directors of Viper’s
On
During the first quarter of 2021, Viper repurchased 869,965 common units for an aggregate of
The repurchase program is authorized to extend through
OPERATIONS AND ACQUISITIONS UPDATE
During the first quarter of 2021, Viper estimates that 134 gross (2.5 net 100% royalty interest) horizontal wells with an average royalty interest of 1.9% were turned to production on its existing acreage position with an average lateral length of 10,584 feet. Of these 134 gross wells, Diamondback is the operator of 50 gross wells with an average royalty interest of 4.2%, and the remaining 84 gross wells, with an average royalty interest of 0.5%, are operated by third parties.
During the first quarter of 2021, Viper did not complete any acquisitions or divestitures, leaving the Company’s footprint of mineral and royalty interests as of
The following table summarizes Viper’s gross well information:
Diamondback Operated |
Third Party Operated |
Total | ||||||
Horizontal wells turned to production (first quarter 2021)(1): | ||||||||
Gross wells | 50 | 84 | 134 | |||||
Net 100% royalty interest wells | 2.1 | 0.4 | 2.5 | |||||
Average percent net royalty interest | 4.2 | % | 0.5 | % | 1.9 | % | ||
Horizontal producing well count (first quarter 2021): | ||||||||
Gross wells | 1,191 | 3,514 | 4,705 | |||||
Net 100% royalty interest wells | 90.7 | 53.4 | 144.2 | |||||
Average percent net royalty interest | 7.6 | % | 1.5 | % | 3.1 | % | ||
Horizontal active development well count (as of |
||||||||
Gross wells | 65 | 406 | 471 | |||||
Net 100% royalty interest wells | 5.8 | 2.9 | 8.7 | |||||
Average percent net royalty interest | 9.0 | % | 0.7 | % | 1.8 | % | ||
Line of sight wells (as of |
||||||||
Gross wells | 101 | 389 | 490 | |||||
Net 100% royalty interest wells | 5.2 | 3.5 | 8.7 | |||||
Average percent net royalty interest | 5.1 | % | 0.9 | % | 1.8 | % |
(1) Average lateral length of 10,584.
There continues to be active development across Viper’s asset base with near-term activity expected to be driven primarily by Diamondback operations. The 471 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. The 490 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 guidance for the full year 2021, as well as average production guidance for Q2 2021 and Q3 2021.
Q2 2021 / Q3 2021 Net Production - MBo/d | 15.00 - 16.00 | |
Q2 2021 / Q3 2021 Net Production - MBoe/d | 25.00 - 26.50 | |
Full Year 2021 Net Production - MBo/d | 15.00 - 16.25 | |
Full Year 2021 Net Production - MBoe/d | 25.00 - 27.00 | |
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) | Assumes actual interest expense for Q1 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 NGLs and ad valorem taxes. |
CONFERENCE CALL
Viper will host a conference call and webcast for investors and analysts to discuss its results for the first 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 adverse industry and macroeconomic conditions, volatile commodity prices, production levels on properties in which Viper has mineral and royalty interests, the effect of the recent presidential and congressional elections on environmental policies and regulations impacting Viper and its operators, any potential regulatory action that may impose production limits on Viper’s mineral and royalty acreage, severe weather conditions (including the impact of the recent severe winter storms on production volumes on Viper’s mineral and royalty acreage), 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 ongoing 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 | $ | 11,727 | $ | 19,121 | |||
Royalty income receivable (net of allowance for credit losses) | 41,791 | 32,210 | |||||
Royalty income receivable—related party | 5,521 | 1,998 | |||||
Other current assets | 505 | 665 | |||||
Total current assets | 59,544 | 53,994 | |||||
Property: | |||||||
Oil and natural gas interests, full cost method of accounting ( |
2,895,616 | 2,895,542 | |||||
Land | 5,688 | 5,688 | |||||
Accumulated depletion and impairment | (521,062 | ) | (496,176 | ) | |||
Property, net | 2,380,242 | 2,405,054 | |||||
Other assets | 2,018 | 2,327 | |||||
Total assets | $ | 2,441,804 | $ | 2,461,375 | |||
Liabilities and Unitholders’ Equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 21 | $ | 43 | |||
Accrued liabilities | 19,679 | 18,262 | |||||
Derivative instruments | 43,155 | 26,593 | |||||
Total current liabilities | 62,855 | 44,898 | |||||
Long-term debt, net | 528,911 | 555,644 | |||||
Total liabilities | 591,766 | 600,542 | |||||
Commitments and contingencies | |||||||
Unitholders’ equity: | |||||||
General partner | 789 | 809 | |||||
Common units (64,949,540 units issued and outstanding as of 65,817,281 units issued and outstanding as of |
611,172 | 633,415 | |||||
Class B units (90,709,946 units issued and outstanding |
1,006 | 1,031 | |||||
612,967 | 635,255 | ||||||
Non-controlling interest | 1,237,071 | 1,225,578 | |||||
Total equity | 1,850,038 | 1,860,833 | |||||
Total liabilities and unitholders’ equity | $ | 2,441,804 | $ | 2,461,375 |
Consolidated Statements of Operations | |||||||
(unaudited, in thousands, except per unit data) | |||||||
Three Months Ended |
|||||||
2021 | 2020 | ||||||
Operating income: | |||||||
Royalty income | $ | 96,512 | $ | 76,829 | |||
Lease bonus income | 325 | 1,622 | |||||
Other operating income | 139 | 241 | |||||
Total operating income | 96,976 | 78,692 | |||||
Costs and expenses: | |||||||
Production and ad valorem taxes | 6,649 | 6,147 | |||||
Depletion | 24,886 | 24,642 | |||||
General and administrative expenses | 2,221 | 2,666 | |||||
Total costs and expenses | 33,756 | 33,455 | |||||
Income (loss) from operations | 63,220 | 45,237 | |||||
Other income (expense): | |||||||
Interest expense, net | (7,860 | ) | (8,963 | ) | |||
Gain (loss) on derivative instruments, net | (31,504 | ) | (7,942 | ) | |||
Gain (loss) on revaluation of investment | — | (10,120 | ) | ||||
Other income, net | 38 | 404 | |||||
Total other expense, net | (39,326 | ) | (26,621 | ) | |||
Income (loss) before income taxes | 23,894 | 18,616 | |||||
Provision for (benefit from) income taxes | 35 | 142,466 | |||||
Net income (loss) | 23,859 | (123,850 | ) | ||||
Net income (loss) attributable to non-controlling interest | 26,879 | 18,319 | |||||
Net income (loss) attributable to |
$ | (3,020 | ) | $ | (142,169 | ) | |
Net income (loss) attributable to common limited partner units: | |||||||
Basic | $ | (0.05 | ) | $ | (2.10 | ) | |
Diluted | $ | (0.05 | ) | $ | (2.10 | ) | |
Weighted average number of common limited partner units outstanding: | |||||||
Basic | 65,360 | 67,822 | |||||
Diluted | 65,360 | 67,823 |
Consolidated Statements of Cash Flows | |||||||
(unaudited, in thousands) | |||||||
Three Months Ended |
|||||||
2021 | 2020 | ||||||
Cash flows from operating activities: | |||||||
Net income (loss) | $ | 23,859 | $ | (123,850 | ) | ||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||
Deferred income taxes expense (benefit) | — | 142,466 | |||||
Depletion | 24,886 | 24,642 | |||||
(Gain) loss on derivative instruments, net | 31,504 | 7,942 | |||||
Net cash payments on derivatives | (14,942 | ) | (453 | ) | |||
(Gain) loss on revaluation of investment | — | 10,120 | |||||
Other | 901 | 961 | |||||
Changes in operating assets and liabilities: | |||||||
Royalty income receivable | (9,581 | ) | 20,129 | ||||
Royalty income receivable—related party | (3,523 | ) | 10,576 | ||||
Accounts payable and accrued liabilities | 1,395 | 3,665 | |||||
Other | 160 | (87 | ) | ||||
Net cash provided by (used in) operating activities | 54,659 | 96,111 | |||||
Cash flows from investing activities: | |||||||
Acquisitions of oil and natural gas interests | (74 | ) | (64,626 | ) | |||
Net cash provided by (used in) investing activities | (74 | ) | (64,626 | ) | |||
Cash flows from financing activities: | |||||||
Proceeds from borrowings under credit facility | — | 92,000 | |||||
Repayment on credit facility | (27,000 | ) | (15,000 | ) | |||
Repurchased units as part of unit buyback | (13,043 | ) | — | ||||
Distributions to public | (9,060 | ) | (30,214 | ) | |||
Distributions to Diamondback | (12,826 | ) | (41,173 | ) | |||
Other | (50 | ) | (429 | ) | |||
Net cash provided by (used in) financing activities | (61,979 | ) | 5,184 | ||||
Net increase (decrease) in cash | (7,394 | ) | 36,669 | ||||
Cash and cash equivalents at beginning of period | 19,121 | 3,602 | |||||
Cash and cash equivalents at end of period | $ | 11,727 | $ | 40,271 |
Selected Operating Data | |||||||||
(unaudited) | |||||||||
Three Months Ended |
Three Months Ended |
Three Months Ended |
|||||||
Production Data: | |||||||||
Oil (MBbls) | 1,395 | 1,597 | 1,587 | ||||||
Natural gas (MMcf) | 3,262 | 3,032 | 2,658 | ||||||
Natural gas liquids (MBbls) | 407 | 446 | 479 | ||||||
Combined volumes (MBOE)(1) | 2,346 | 2,549 | 2,509 | ||||||
Average daily oil volumes (BO/d)(2) | 15,500 | 17,359 | 17,441 | ||||||
Average daily combined volumes (BOE/d)(2) | 26,066 | 27,699 | 27,575 | ||||||
Average sales prices(2): | |||||||||
Oil ($/Bbl) | $ | 56.16 | $ | 40.36 | $ | 45.49 | |||
Natural gas ($/Mcf) | $ | 2.77 | $ | 1.36 | $ | 0.13 | |||
Natural gas liquids ($/Bbl) | $ | 22.42 | $ | 14.71 | $ | 8.94 | |||
Combined ($/BOE)(3) | $ | 41.14 | $ | 29.48 | $ | 30.62 | |||
Oil, hedged ($/Bbl)(4) | $ | 45.45 | $ | 30.48 | $ | 45.49 | |||
Natural gas, hedged ($/Mcf)(4) | $ | 2.77 | $ | 0.84 | $ | (0.04 | ) | ||
Natural gas liquids ($/Bbl)(4) | $ | 22.42 | $ | 14.71 | $ | 8.94 | |||
Combined price, hedged ($/BOE)(4) | $ | 34.77 | $ | 22.68 | $ | 30.44 | |||
Average Costs ($/BOE): | |||||||||
Production and ad valorem taxes | $ | 2.83 | $ | 2.17 | $ | 2.45 | |||
General and administrative - cash component(5) | 0.81 | 0.66 | 0.91 | ||||||
Total operating expense - cash | $ | 3.64 | $ | 2.83 | $ | 3.36 | |||
General and administrative - non-cash unit compensation expense | $ | 0.13 | $ | 0.13 | $ | 0.15 | |||
Interest expense, net | $ | 3.35 | $ | 3.19 | $ | 3.57 | |||
Depletion | $ | 10.61 | $ | 11.10 | $ | 9.82 |
(1) | Bbl equivalents are calculated using a conversion rate of six Mcf per one Bbl. | |
(2) | Average daily volumes and average sales prices presented are based on actual production volumes and not calculated utilizing the rounded production volumes presented in the table above. | |
(3) | Realized price net of all deducts for gathering, transportation and processing. | |
(4) | Hedged prices reflect the impact of cash settlements of our matured commodity derivative transactions on our average sales prices. | |
(5) | 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
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 |
$ | (3,020 | ) |
Net income (loss) attributable to non-controlling interest | 26,879 | ||
Net income (loss) | 23,859 | ||
Interest expense, net | 7,860 | ||
Non-cash unit-based compensation expense | 315 | ||
Depletion | 24,886 | ||
Non-cash (gain) loss on derivative instruments | 16,562 | ||
Provision for (benefit from) income taxes | 35 | ||
Consolidated Adjusted EBITDA | 73,517 | ||
Less: Adjusted EBITDA attributable to non-controlling interest(1) | 42,779 | ||
Adjusted EBITDA attributable to |
$ | 30,738 | |
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: | |||
Income taxes payable | $ | (35 | ) |
Debt service, contractual obligations, fixed charges and reserves | (3,047 | ) | |
Cash paid for tax withholding on vested common units | (20 | ) | |
Distribution equivalent rights payments | (24 | ) | |
Preferred distributions | (45 | ) | |
Cash available for distribution to |
$ | 27,567 | |
Common limited partner units outstanding | 64,950 | ||
Cash available for distribution per limited partner unit | $ | 0.42 | |
Cash per unit approved for distribution | $ | 0.25 |
(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 |
$ | (3,020 | ) | $ | (0.05 | ) | |
Net income (loss) attributable to non-controlling interest | 26,879 | 0.41 | |||||
Net income (loss) | 23,859 | 0.36 | |||||
Non-cash (gain) loss on derivative instruments, net | 16,562 | 0.25 | |||||
Adjusted net income (loss)(1) | 40,421 | 0.61 | |||||
Less: Adjusted net income (loss) attributed to non-controlling interests(1) | 45,472 | 0.69 | |||||
Adjusted net income (loss) attributable to |
$ | (5,051 | ) | $ | (0.08 | ) | |
Weighted average common units outstanding: | |||||||
Basic | 65,360 | ||||||
Diluted | 65,472 |
(1) Calculated using diluted shares (non-GAAP)
RECONCILIATION OF LONG-TERM DEBT TO NET DEBT
The Company defines net debt as debt 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 Q1 Principal Borrowings/ (Repayments) |
2020 |
2020 |
2020 |
2020 |
||||||||||||||||||
(in thousands) | |||||||||||||||||||||||
Total long-term debt(1) | $ | 536,938 | $ | (27,000 | ) | $ | 563,938 | $ | 606,438 | $ | 639,438 | $ | 673,500 | ||||||||||
Cash and cash equivalents | (11,727 | ) | (19,121 | ) | (7,374 | ) | (9,663 | ) | (40,271 | ) | |||||||||||||
Net debt | $ | 525,211 | $ | 544,817 | $ | 599,064 | $ | 629,775 | $ | 633,229 |
(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) | |||||||||||
Q2 2021 | Q3 2021 | Q4 2021 | |||||||||
Collars - WTI ( |
10,000 | 10,000 | 10,000 | ||||||||
Floor Price | $ | 30.00 | $ | 30.00 | $ | 30.00 | |||||
Ceiling Price | $ | 43.05 | $ | 43.05 | $ | 43.05 |
Investor Contacts:
+1 432.221.7467
alawlis@viperenergy.com
+1 432.221.7420
agilfillian@viperenergy.com
Source:
Source: Viper Energy Partners LP