FOURTH QUARTER HIGHLIGHTS
- Q4 2021 average production of 18,370 bo/d (31,359 boe/d)
- Q4 2021 consolidated net income (including non-controlling interest) of
$117.0 million ; net income attributable toViper Energy Partners LP of$39.5 million , or$0.50 per common unit - Adjusted net income (as defined and reconciled below) of
$84.4 million , or$1.07 per common unit - Q4 2021 cash distribution of
$0.47 per common unit, representing approximately 70% of total cash available for distribution;$0.47 distribution is up 24% quarter over quarter and implies a 7.2% annualized yield based on theFebruary 18, 2022 unit closing price of$26.21 - Q4 2021 cash available for distribution of
$0.67 per common unit represents a Company record; 12% higher than the previous record of$0.60 per common unit generated in Q2 2018 - Repurchased 574,200 common units in Q4 2021 for an aggregate of
$12 .4 million; from the end of the fourth quarter throughJanuary 31, 2022 , Viper repurchased an additional 1,580,200 common units for an aggregate of$39.3 million - Consolidated adjusted EBITDA (as defined and reconciled below) of
$123.9 million and cash available for distribution to Viper’s common units (as reconciled below) of$52.8 million - Ended the fourth quarter of 2021 with total long-term debt of
$783.9 million and net debt of$744.5 million (as defined and reconciled below) - 179 total gross (5.1 net 100% royalty interest) horizontal wells turned to production on Viper’s acreage during Q4 2021 with an average lateral length of 10,048 feet
- As previously announced, completed acquisition of certain mineral and royalty interests from
Swallowtail Royalties LLC andSwallowtail Royalties II LLC (“Swallowtail”); added approximately 2,313 net royalty acres primarily in theNorthern Midland Basin , roughly 62% of which are operated by Diamondback - In addition to the Swallowtail acquisition, acquired 350 Diamondback-operated net royalty acres for an aggregate purchase price of
$49.1 million during Q4 2021 - Subsequent to the end of the fourth quarter of 2021, divested 325 net royalty acres for cash consideration of
$29 .3 million, subject to post-close adjustments; represents third party operated acreage located entirely inUpton andReagan counties
FULL YEAR 2021 HIGHLIGHTS
- Full year 2021 average production of 16,625 bo/d (28,110 boe/d)
- Full year 2021 consolidated net income (including non-controlling interest) of
$256.7 million ; net income attributable toViper Energy Partners LP of$57.9 million , or$0.85 per common unit - Declared distributions of
$1.43 per common unit during full year 2021; generated$2.10 per common unit of total cash available for distribution - Repurchased 2,612,840 units during full year 2021 for an aggregate of
$46.0 million , representing an average price of$17.60 per unit - Generated full year 2021 consolidated adjusted EBITDA (as defined and reconciled below) of
$373.2 million - Proved reserves as of
December 31, 2021 of 127,888 Mboe (71% PDP, 69,240 Mbo), up 29% year over year with oil up 20% from year end 2020 - 720 total gross (14.0 net 100% royalty interest) horizontal wells turned to production during 2021 with an average lateral length of 9,823 feet
- Acquired approximately 2,706 net royalty acres for an aggregate purchase price of
$617.0 million ; increased Diamondback-operated acreage by 1,835 net royalty acres - 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
2022 OUTLOOK
- Initiating average daily production guidance for the first half of 2022 of 17,750 to 18,500 bo/d (29,500 to 30,750 boe/d)
- Initiating full year 2022 average production guidance of 17,750 to 19,000 bo/d (29,500 to 31,500 boe/d)
- As of
February 8, 2022 , there were approximately 618 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 (10.6 net 100% royalty interest wells) - Approximately 563 gross (11.6 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
- Approximately 90% of distributions paid in 2022 are expected to be reasonably estimated to constitute non-taxable reductions to the tax basis, and not dividends, for
U.S. federal income tax purposes
“During the fourth quarter, Viper generated record financial and operating results, highlighted by the
MANAGEMENT CHANGES
FINANCIAL UPDATE
Viper’s fourth quarter 2021 average unhedged realized prices were
During the fourth quarter of 2021, the Company recorded total operating income of
As of
FOURTH QUARTER 2021 CASH DISTRIBUTION & CAPITAL RETURN PROGRAM
The Board of Directors of Viper’s
On
During the fourth quarter of 2021, Viper repurchased 574,200 common units for an aggregate of
From the end of the fourth quarter through
OPERATIONS AND ACQUISITIONS UPDATE
During the fourth quarter of 2021, Viper estimates that 179 gross (5.1 net 100% royalty interest) horizontal wells with an average royalty interest of 2.9% were turned to production on its acreage position with an average lateral length of 10,048 feet. Of these 179 gross wells, Diamondback is the operator of 40 gross wells with an average royalty interest of 9.3%, and the remaining 139 gross wells, with an average royalty interest of 1.0%, are operated by third parties.
As previously announced, on
In addition to the Swallowtail acquisition, during the fourth quarter of 2021 Viper acquired 350 net royalty acres for an aggregate of approximately
As a result of the acquisitions completed during the fourth quarter of 2021, the Company’s footprint of mineral and royalty interests as of
Subsequent to the end of the fourth quarter, Viper completed a divestiture of approximately 325 net royalty acres for total proceeds of approximately
The following table summarizes Viper’s gross well information:
Diamondback Operated | Third Party Operated | Total | ||||||
Horizontal wells turned to production (fourth quarter 2021)(1): | ||||||||
Gross wells | 40 | 139 | 179 | |||||
Net 100% royalty interest wells | 3.7 | 1.4 | 5.1 | |||||
Average percent net royalty interest | 9.3% | 1.0% | 2.9% | |||||
Horizontal wells turned to production (year ended | ||||||||
Gross wells | 158 | 562 | 720 | |||||
Net 100% royalty interest wells | 10.2 | 3.8 | 14.0 | |||||
Average percent net royalty interest | 6.5% | 0.7% | 1.9% | |||||
Horizontal producing well count (fourth quarter 2021): | ||||||||
Gross wells | 1,335 | 4,371 | 5,706 | |||||
Net 100% royalty interest wells | 101.8 | 59.4 | 161.2 | |||||
Average percent net royalty interest | 7.6% | 1.4% | 2.8% | |||||
Horizontal active development well count (as of | ||||||||
Gross wells | 106 | 512 | 618 | |||||
Net 100% royalty interest wells | 6.8 | 3.8 | 10.6 | |||||
Average percent net royalty interest | 6.4% | 0.7% | 1.7% | |||||
Line of sight wells (as of | ||||||||
Gross wells | 135 | 428 | 563 | |||||
Net 100% royalty interest wells | 7.8 | 3.8 | 11.6 | |||||
Average percent net royalty interest | 5.8% | 0.9% | 2.1% |
(1) Average lateral length of 10,048 feet.
(2) Average lateral length of 9,823 feet.
The 618 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 39 gross rigs operating on Viper’s acreage, six of which are operated by Diamondback. The 563 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.
YEAR END RESERVES UPDATE
Proved reserves at year-end 2021 of 127,888 Mboe (69,240 Mbo) represent a 29% increase over year-end 2020 reserves. The year-end 2021 proved reserves have a PV-10 value (as defined and reconciled below) of approximately
Proved developed reserves increased by 26% year over year to 91,170 Mboe (49,280 Mbo) as of
Net proved reserve additions of 38,756 Mboe resulted in a reserve replacement ratio of 378% (defined as the sum of extensions, discoveries, revisions, purchases and divestitures, divided by annual production). The organic reserve replacement ratio was 293% (defined as the sum of extensions, discoveries and revisions, divided by annual production).
Extensions and discoveries of 30,981 Mboe are primarily attributable to the drilling of 407 new wells and from 336 new proved undeveloped locations added. The Company’s negative revisions of previous estimated quantities of 918 Mboe were driven primarily by a reassessment of Diamondback’s expected development plan following two large acquisitions. There were offsetting positive revisions due to price increases and improved well performance. The purchase of reserves in place of 9,102 Mboe was due to multiple acquisitions of certain mineral and royalty interests, primarily the Swallowtail acquisition.
Oil (MBbls) | Liquids (MBbls) | Gas (MMcf) | MBOE | ||||||||
As of December 31, 2020 | 57,530 | 21,953 | 119,450 | 99,392 | |||||||
Purchase of reserves in place | 5,246 | 2,264 | 9,549 | 9,102 | |||||||
Extensions and discoveries | 17,256 | 7,182 | 39,256 | 30,981 | |||||||
Revisions of previous estimates | (4,544 | ) | (1,339 | ) | 29,788 | (918 | ) | ||||
Divestitures | (180 | ) | (114 | ) | (681 | ) | (409 | ) | |||
Production | (6,068 | ) | (1,913 | ) | (13,672 | ) | (10,260 | ) | |||
As of December 31, 2021 | 69,240 | 28,033 | 183,690 | 127,888 |
As the owner of mineral and royalty interests, Viper incurred no exploration and development costs during the year ended
2021 | 2020 | 2019 | ||||||
(in thousands) | ||||||||
Acquisition costs: | ||||||||
Proved properties | $ | 138,882 | $ | 9,509 | $ | 318,525 | ||
Unproved properties | 479,041 | 56,169 | 833,221 | |||||
Total | $ | 617,923 | $ | 65,678 | $ | 1,151,746 |
GUIDANCE UPDATE
Below is Viper’s preliminary guidance for the full year 2022, as well as average production guidance for the first half of 2022.
Q1 2022 / Q2 2022 Net Production - MBo/d | 17.75 - 18.50 |
Q1 2022 / Q2 2022 Net Production - MBoe/d | 29.50 - 30.75 |
Full Year 2022 Net Production - MBo/d | 17.75 - 19.00 |
Full Year 2022 Net Production - MBoe/d | 29.50 - 31.50 |
Unit costs ($/boe) | |
Depletion | |
Cash G&A | |
Non-Cash Unit-Based Compensation | |
Interest Expense(1) | |
Production and Ad Valorem Taxes (% of Revenue) (2) | 7% - 8% |
(1) | Expected interest for the full year 2022 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 fourth 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 Section 27A of the Securities Act and Section 21E of the Exchange Act, which involve risks, uncertainties, and assumptions. All statements, other than statements of historical fact, including statements regarding Viper’s: future performance; business strategy; future operations; estimates and projections of operating income, losses, costs and expenses, returns, cash flow, and financial position; production levels on properties in which Viper has mineral and royalty interests, developmental activity by other operators; reserve estimates and Viper’s ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of (including Diamondback’s plans for developing Viper’s acreage and Viper’s cash distribution policy and common unit repurchase program) are forward-looking statements. When used in this news release, the words “aim,” “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “future,” “guidance,” “intend,” “may,” “model,” “outlook,” “plan,” “positioned,” “potential,” “predict,” “project,” “seek,” “should,” “target,” “will,” “would,” and similar expressions (including the negative of such terms) as they relate to Viper are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Although Viper believes that the expectations and assumptions reflected in its forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond its control. Accordingly, forward-looking statements are not guarantees of Viper’s future performance and the actual outcomes could differ materially from what Viper expressed in its forward-looking statements.
Factors that could cause the outcomes to differ materially include (but are not limited to) the following: changes in supply and demand levels for oil, natural gas, and natural gas liquids, and the resulting impact on the price for those commodities; the impact of public health crises, including epidemic or pandemic diseases such as the COVID-19 pandemic, and any related company or government policies or actions; actions taken by the members of
In light of these factors, the events anticipated by Viper’s forward-looking statements may not occur at the time anticipated or at all. Moreover, the new risks emerge from time to time. Viper cannot predict all risks, nor can it assess the impact of all factors on its business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those anticipated by any forward-looking statements it may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this news release. All forward-looking statements speak only as of the date of this news release or, if earlier, as of the date they were made. Viper does not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.
Consolidated Balance Sheets | |||||||
(unaudited, in thousands, except unit amounts) | |||||||
2021 | 2020 | ||||||
Assets | |||||||
Current assets: | |||||||
Cash and cash equivalents | $ | 39,448 | $ | 19,121 | |||
Royalty income receivable (net of allowance for credit losses) | 68,568 | 32,210 | |||||
Royalty income receivable—related party | 2,144 | 1,998 | |||||
Other current assets | 989 | 665 | |||||
Total current assets | 111,149 | 53,994 | |||||
Property: | |||||||
Oil and natural gas interests, full cost method of accounting ( | 3,513,590 | 2,895,542 | |||||
Land | 5,688 | 5,688 | |||||
Accumulated depletion and impairment | (599,163 | ) | (496,176 | ) | |||
Property, net | 2,920,115 | 2,405,054 | |||||
Other assets | 2,757 | 2,327 | |||||
Total assets | $ | 3,034,021 | $ | 2,461,375 | |||
Liabilities and Unitholders’ Equity | |||||||
Current liabilities: | |||||||
Accounts payable | $ | 69 | $ | 43 | |||
Accrued liabilities | 20,980 | 18,262 | |||||
Derivative instruments | 3,417 | 26,593 | |||||
Total current liabilities | 24,466 | 44,898 | |||||
Long-term debt, net | 776,727 | 555,644 | |||||
Total liabilities | 801,193 | 600,542 | |||||
Commitments and contingencies | |||||||
Unitholders’ equity: | |||||||
General Partner | 729 | 809 | |||||
Common units (78,546,403 units issued and outstanding as of | 813,161 | 633,415 | |||||
Class B units (90,709,946 units issued and outstanding | 931 | 1,031 | |||||
814,821 | 635,255 | ||||||
Non-controlling interest | 1,418,007 | 1,225,578 | |||||
Total equity | 2,232,828 | 1,860,833 | |||||
Total liabilities and unitholders’ equity | $ | 3,034,021 | $ | 2,461,375 | |||
Consolidated Statements of Operations | |||||||||||||||
(unaudited, in thousands, except per unit data) | |||||||||||||||
Three Months Ended | Year Ended | ||||||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||||||
Operating income: | |||||||||||||||
Royalty income | $ | 163,915 | $ | 75,124 | $ | 501,534 | $ | 246,981 | |||||||
Lease bonus income | 1,731 | 900 | 2,763 | 2,585 | |||||||||||
Other operating income | 141 | 299 | 620 | 1,060 | |||||||||||
Total operating income | 165,787 | 76,323 | 504,917 | 250,626 | |||||||||||
Costs and expenses: | |||||||||||||||
Production and ad valorem taxes | 9,132 | 5,538 | 32,558 | 19,844 | |||||||||||
Depletion | 28,757 | 28,297 | 102,987 | 100,501 | |||||||||||
Impairment | — | 69,202 | — | 69,202 | |||||||||||
General and administrative expenses | 1,682 | 2,005 | 7,800 | 8,165 | |||||||||||
Total costs and expenses | 39,571 | 105,042 | 143,345 | 197,712 | |||||||||||
Income (loss) from operations | 126,216 | (28,719 | ) | 361,572 | 52,914 | ||||||||||
Other income (expense): | |||||||||||||||
Interest expense, net | (9,883 | ) | (8,130 | ) | (34,044 | ) | (33,000 | ) | |||||||
Gain (loss) on derivative instruments, net | 1,240 | (16,122 | ) | (69,409 | ) | (63,591 | ) | ||||||||
Gain (loss) on revaluation of investment | — | 105 | — | (8,556 | ) | ||||||||||
Other income, net | 2 | 175 | 79 | 1,286 | |||||||||||
Total other expense, net | (8,641 | ) | (23,972 | ) | (103,374 | ) | (103,861 | ) | |||||||
Income (loss) before income taxes | 117,575 | (52,691 | ) | 258,198 | (50,947 | ) | |||||||||
Provision for (benefit from) income taxes | 580 | — | 1,521 | 142,466 | |||||||||||
Net income (loss) | 116,995 | (52,691 | ) | 256,677 | (193,413 | ) | |||||||||
Net income (loss) attributable to non-controlling interest | 77,530 | (25,072 | ) | 198,738 | (1,109 | ) | |||||||||
Net income (loss) attributable to | $ | 39,465 | $ | (27,619 | ) | $ | 57,939 | $ | (192,304 | ) | |||||
Net income (loss) attributable to common limited partner units: | |||||||||||||||
Basic | $ | 0.50 | $ | (0.41 | ) | $ | 0.85 | $ | (2.84 | ) | |||||
Diluted | $ | 0.50 | $ | (0.41 | ) | $ | 0.85 | $ | (2.84 | ) | |||||
Weighted average number of common limited partner units outstanding: | |||||||||||||||
Basic | 78,986 | 67,253 | 68,319 | 67,686 | |||||||||||
Diluted | 79,058 | 67,253 | 68,391 | 67,686 | |||||||||||
Consolidated Statements of Cash Flows | |||||||||||||||
(unaudited, in thousands) | |||||||||||||||
Three Months Ended | Year Ended | ||||||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||||||
Cash flows from operating activities: | |||||||||||||||
Net income (loss) | $ | 116,995 | $ | (52,691 | ) | $ | 256,677 | $ | (193,413 | ) | |||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||
Deferred income tax expense (benefit) | — | — | — | 142,466 | |||||||||||
Depletion | 28,757 | 28,297 | 102,987 | 100,501 | |||||||||||
Impairment | — | 69,202 | — | 69,202 | |||||||||||
(Gain) loss on derivative instruments, net | (1,240 | ) | 16,122 | 69,409 | 63,591 | ||||||||||
Net cash receipts (payments) on derivatives | (31,397 | ) | (18,280 | ) | (92,585 | ) | (36,998 | ) | |||||||
(Gain) loss on revaluation of investment | — | (105 | ) | — | 8,556 | ||||||||||
Other | 1,378 | 908 | 4,710 | 3,589 | |||||||||||
Changes in operating assets and liabilities: | |||||||||||||||
Royalty income receivable | (21,435 | ) | (102 | ) | (36,358 | ) | 25,879 | ||||||||
Royalty income receivable—related party | 19,878 | 12,913 | (146 | ) | 8,578 | ||||||||||
Other | (5,494 | ) | (2,914 | ) | 2,420 | 4,605 | |||||||||
Net cash provided by (used in) operating activities | 107,442 | 53,350 | 307,114 | 196,556 | |||||||||||
Cash flows from investing activities: | |||||||||||||||
Acquisitions of oil and natural gas interests | (274,448 | ) | (1,170 | ) | (281,176 | ) | (65,678 | ) | |||||||
Proceeds from sale of assets | — | 36,496 | — | 38,594 | |||||||||||
Proceeds from the sale of investments | — | 5,539 | — | 10,801 | |||||||||||
Net cash provided by (used in) investing activities | (274,448 | ) | 40,865 | (281,176 | ) | (16,283 | ) | ||||||||
Cash flows from financing activities: | |||||||||||||||
Proceeds from borrowings under credit facility | 243,000 | 9,000 | 330,000 | 104,000 | |||||||||||
Repayment on credit facility | (31,000 | ) | (51,500 | ) | (110,000 | ) | (116,500 | ) | |||||||
Repayment of senior notes | — | — | — | (19,697 | ) | ||||||||||
Debt issuance costs | (17 | ) | (21 | ) | (2,885 | ) | (111 | ) | |||||||
Repurchased units as part of unit buyback | (12,437 | ) | (24,026 | ) | (45,999 | ) | (24,026 | ) | |||||||
Distributions to public | (29,840 | ) | (6,731 | ) | (75,942 | ) | (45,674 | ) | |||||||
Distributions to Diamondback | (34,772 | ) | (9,170 | ) | (100,685 | ) | (62,282 | ) | |||||||
Other | (20 | ) | (20 | ) | (100 | ) | (464 | ) | |||||||
Net cash provided by (used in) financing activities | 134,914 | (82,468 | ) | (5,611 | ) | (164,754 | ) | ||||||||
Net increase (decrease) in cash and cash equivalents | (32,092 | ) | 11,747 | 20,327 | 15,519 | ||||||||||
Cash, cash equivalents and restricted cash at beginning of period | 71,540 | 7,374 | 19,121 | 3,602 | |||||||||||
Cash, cash equivalents and restricted cash at end of period | $ | 39,448 | $ | 19,121 | $ | 39,448 | $ | 19,121 | |||||||
Selected Operating Data | |||||||||||
(unaudited) | |||||||||||
Three Months Ended | Year Ended | ||||||||||
2021 | 2020 | 2021 | 2020 | ||||||||
Production Data: | |||||||||||
Oil (MBbls) | 1,690 | 1,597 | 6,068 | 5,956 | |||||||
Natural gas (MMcf) | 3,844 | 3,032 | 13,672 | 11,486 | |||||||
Natural gas liquids (MBbls) | 554 | 446 | 1,913 | 1,848 | |||||||
Combined volumes (MBOE)(1) | 2,885 | 2,549 | 10,260 | 9,718 | |||||||
Average daily oil volumes (BO/d) | 18,370 | 17,359 | 16,625 | 16,272 | |||||||
Average daily combined volumes (BOE/d) | 31,359 | 27,699 | 28,110 | 26,551 | |||||||
Average sales prices: | |||||||||||
Oil ($/Bbl) | $ | 74.00 | $ | 40.36 | $ | 65.51 | $ | 36.58 | |||
Natural gas ($/Mcf) | $ | 4.82 | $ | 1.36 | $ | 3.60 | $ | 0.79 | |||
Natural gas liquids ($/Bbl) | $ | 36.65 | $ | 14.71 | $ | 28.66 | $ | 10.88 | |||
Combined ($/BOE)(2) | $ | 56.82 | $ | 29.48 | $ | 48.88 | $ | 25.41 | |||
Oil, hedged ($/Bbl)(3) | $ | 55.42 | $ | 30.48 | $ | 50.25 | $ | 32.00 | |||
Natural gas, hedged ($/Mcf)(3) | $ | 4.82 | $ | 0.84 | $ | 3.60 | $ | 0.02 | |||
Natural gas liquids ($/Bbl)(3) | $ | 36.65 | $ | 14.71 | $ | 28.66 | $ | 10.88 | |||
Combined price, hedged ($/BOE)(3) | $ | 45.94 | $ | 22.68 | $ | 39.86 | $ | 21.71 | |||
Average Costs ($/BOE): | |||||||||||
Production and ad valorem taxes | $ | 3.17 | $ | 2.17 | $ | 3.17 | $ | 2.04 | |||
General and administrative - cash component(4) | 0.48 | 0.66 | 0.65 | 0.71 | |||||||
Total operating expense - cash | $ | 3.65 | $ | 2.83 | $ | 3.82 | $ | 2.75 | |||
General and administrative - non-cash unit compensation expense | $ | 0.10 | $ | 0.13 | $ | 0.11 | $ | 0.13 | |||
Interest expense, net | $ | 3.43 | $ | 3.19 | $ | 3.32 | $ | 3.40 | |||
Depletion | $ | 9.97 | $ | 11.10 | $ | 10.04 | $ | 10.34 | |||
(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 | $ | 39,465 | $ | 16,832 | $ | 4,662 | $ | (3,020 | ) | ||||||
Net income (loss) attributable to non-controlling interest | 77,530 | 56,613 | 37,716 | 26,879 | |||||||||||
Net income (loss) | 116,995 | 73,445 | 42,378 | 23,859 | |||||||||||
Interest expense, net | 9,883 | 8,328 | 7,973 | 7,860 | |||||||||||
Non-cash unit-based compensation expense | 276 | 243 | 338 | 315 | |||||||||||
Depletion | 28,757 | 25,366 | 23,978 | 24,886 | |||||||||||
Non-cash (gain) loss on derivative instruments | (32,637 | ) | (15,707 | ) | 8,606 | 16,562 | |||||||||
Provision for (benefit from) income taxes | 580 | 906 | — | 35 | |||||||||||
Consolidated Adjusted EBITDA | 123,854 | 92,581 | 83,273 | 73,517 | |||||||||||
Less: Adjusted EBITDA attributable to non- controlling interest(1) | 66,242 | 54,269 | 48,637 | 42,779 | |||||||||||
Adjusted EBITDA attributable to | $ | 57,612 | $ | 38,312 | $ | 34,636 | $ | 30,738 | |||||||
Adjustments to reconcile Adjusted EBITDA to cash available for distribution: | |||||||||||||||
Income taxes payable | $ | (580 | ) | $ | (906 | ) | $ | — | $ | (35 | ) | ||||
Debt service, contractual obligations, fixed charges and reserves | (4,094 | ) | (2,996 | ) | (4,187 | ) | (3,047 | ) | |||||||
Cash paid for tax withholding on vested common units | — | — | — | (20 | ) | ||||||||||
Distribution equivalent rights payments | (52 | ) | (62 | ) | (55 | ) | (24 | ) | |||||||
Preferred distributions | (45 | ) | (45 | ) | (45 | ) | (45 | ) | |||||||
Cash available for distribution to | $ | 52,841 | $ | 34,303 | $ | 30,349 | $ | 27,567 | |||||||
Common limited partner units outstanding | 78,546 | 63,831 | 64,546 | 64,950 | |||||||||||
Cash available for distribution per limited partner unit | $ | 0.67 | $ | 0.54 | $ | 0.47 | $ | 0.42 | |||||||
Cash per unit approved for distribution | $ | 0.47 | $ | 0.38 | $ | 0.33 | $ | 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 | $ | 39,465 | $ | 0.50 | |||
Net income (loss) attributable to non-controlling interest | 77,530 | 0.98 | |||||
Net income (loss) | 116,995 | 1.48 | |||||
Non-cash (gain) loss on derivative instruments, net | (32,637 | ) | (0.41 | ) | |||
Adjusted net income (loss) | 84,358 | 1.07 | |||||
Less: Adjusted net income (loss) attributed to non-controlling interests | 55,627 | 0.71 | |||||
Adjusted net income (loss) attributable to | $ | 28,731 | $ | 0.36 | |||
Weighted average common units outstanding: | |||||||
Basic | 78,986 | ||||||
Diluted | 79,058 |
RECONCILIATION OF LONG-TERM DEBT TO NET DEBT
The Company defines net debt as debt (excluding debt issuance costs, 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.
Net Q4 Principal Borrowings/ (Repayments) | ||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||
Total long-term debt(1) | $ | 783,938 | $ | 212,000 | $ | 571,938 | $ | 541,938 | $ | 536,938 | $ | 563,938 | ||||||||||
Cash and cash equivalents | (39,448 | ) | (41,515 | ) | (42,422 | ) | (11,727 | ) | (19,121 | ) | ||||||||||||
Net debt | $ | 744,490 | $ | 530,423 | $ | 499,516 | $ | 525,211 | $ | 544,817 |
(1) Excludes debt issuance costs, discounts & premiums.
PV-10
PV-10 is the Company’s estimate of the present value of the future net revenues from proved oil and natural gas reserves after deducting estimated production and ad valorem taxes, future capital costs and operating expenses, but before deducting any estimates of future income taxes. The estimated future net revenues are discounted at an annual rate of 10% to determine their “present value.” The Company believes PV-10 to be an important measure for evaluating the relative significance of its oil and natural gas properties and that the presentation of the non-GAAP financial measure of PV-10 provides useful information to investors because it is widely used by professional analysts and investors in evaluating oil and natural gas companies. Because there are many unique factors that can impact an individual company when estimating the amount of future income taxes to be paid, the Company believes the use of a pre-tax measure is valuable for evaluating the Company. The Company believes that PV-10 is a financial measure routinely used and calculated similarly by other companies in the oil and natural gas industry.
The following table reconciles PV-10 to the Company’s standardized measure of discounted future net cash flows, the most directly comparable measure calculated and presented in accordance with GAAP. PV-10 should not be considered as an alternative to the standardized measure as computed under GAAP.
(in thousands) | ||
Standardized measure of discounted future net cash flows after taxes | $ | 2,093,117 |
Add: Present value of future income tax discounted at 10% | 254,053 | |
PV-10 | $ | 2,347,170 |
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) | ||||||||||||||
Q1 2022 | Q2 2022 | Q3 2022 | Q4 2022 | |||||||||||
Collars - WTI ( | 2,500 | 2,000 | 4,000 | — | ||||||||||
Floor Price | $ | 45.00 | $ | 45.00 | $ | 45.00 | $ | — | ||||||
Ceiling Price | $ | 79.55 | $ | 80.15 | $ | 92.65 | $ | — | ||||||
Deferred Premium Puts - WTI ( | 9,500 | 10,000 | 8,000 | — | ||||||||||
Strike | $ | 47.51 | $ | 47.50 | $ | 47.50 | $ | — | ||||||
Premium | $ | (1.57 | ) | $ | (1.49 | ) | $ | (1.52 | ) | $ | — |
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 |
Natural Gas (Mmbtu/day, $/Mmbtu) | |||||||||||||||
Q1 2023 | Q2 2023 | Q3 2023 | Q4 2023 | ||||||||||||
Natural Gas Basis Swaps - | 10,000 | 10,000 | 10,000 | 10,000 | |||||||||||
Swap Price | $ | (1.02 | ) | $ | (1.02 | ) | $ | (1.02 | ) | $ | (1.02 | ) |
Investor Contact:
+1 432.221.7420
agilfillian@viperenergy.com
Source:
Source:
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