(EDGAR Online via COMTEX) -- ITEM 2.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this report as well as our audited financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2019. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs, and expected performance. Actual results and the timing of events may differ materially from those contained in these forward-looking statements due to a number of factors. See "Part II. Item 1A. Risk Factors" and "Cautionary Statement Regarding Forward-Looking Statements."
We are a publicly traded Delaware limited partnership formed by Diamondback on February 27, 2014 to, among other things, own, acquire and exploit oil and natural gas properties in North America. We are currently focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties in the Permian Basin and the Eagle Ford Shale. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.
As of March 31, 2020, our general partner had a 100% general partner interest in us, and Diamondback owned 731,500 common units and all of our 90,709,946 outstanding Class B units, representing approximately 58% of our total units outstanding. Diamondback also owns and controls our general partner.
COVID-19 and Recent Collapse in Commodity Prices
On March 11, 2020, the World Health Organization characterized the global outbreak of the novel strain of coronavirus, COVID-19, as a "pandemic." To limit the spread of COVID-19, governments have taken various actions including the issuance of stay-at-home orders and social distancing guidelines, causing some businesses to suspend operations and a reduction in demand for many products from direct or ultimate customers. Such actions have resulted in a swift and unprecedented reduction in international and U.S. economic activity which, in turn, has adversely affected the demand for oil and natural gas and caused significant volatility and disruption of the financial markets.
In early March 2020, oil prices dropped sharply, and then continued to decline reaching levels below zero dollars per barrel. This was a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including the announcement of price reductions and production increases by OPEC members and other exporting nations and the ongoing COVID-19 pandemic. The commodity prices are expected to continue to be volatile as a result of changes in oil and natural gas production, inventories and demand, as well as national and international economic performance. We cannot predict when prices will improve and stabilize.
As a result of the reduction in crude oil demand caused by factors discussed above, Diamondback and other operators on properties in which we have mineral and royalty interests lowered their 2020 capital budgets and production guidance, curtailed near term production and reduced their rig count, all of which may be subject to further reductions or curtailments if the commodity markets and macroeconomic conditions do not improve. These actions have had and are expected to continue to have an adverse effect on our business, financial results and cash flows.
Although after performing the ceiling test for the quarter ended March 31, 2020, we were not required to record an impairment on our proved oil and natural gas interests, if the commodity prices continue to fall, we will be required to record impairments in future periods and such impairments may be material. In addition, the administrative agent under the Operating Company's revolving credit facility has recommended that our borrowing base be decreased to $580.0 million, which is expected to be effective mid May 2020. The decrease is subject to approval by the requisite lenders. Under the new expected borrowing base, the Operating Company would have had $406.5 million of availability for future borrowings under the revolving credit facility as of March 31, 2020. If commodity prices continue at current levels or decrease further, our production, proved reserves and cash flows will be adversely impacted. Our business may be further adversely impacted by any government rule, regulation or order that may impose production limits in the Permian Basin or Eagle Ford Shale, as well as pipeline capacity and storage constraints.
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During the first quarter of 2020, we acquired mineral and royalty interests, from unrelated third-party sellers', representing 4,948 gross (410 net royalty) acres in the Permian Basin for an aggregate purchase price of approximately $63.4 million, subject to post-closing adjustments and, as of March 31, 2020, had mineral and royalty interests representing 24,714 net royalty acres. We funded these acquisitions with cash on hand and borrowings under the Operating Company's revolving credit facility.
Cash Distribution Policy Update
On April 30, 2020, the board of directors of our general partner declared a cash distribution for the three months ended March 31, 2020 of $0.10 per common unit. The distribution is payable on May 21, 2020 to eligible common unitholders of record at the close of business on May 14, 2020. This distribution represents 25% of total cash available for distribution with the remaining cash flow expected to be retained to strengthen our balance sheet. The board of directors of our general partner intends to review this distribution policy quarterly.
Production and Operational Update
Our average daily production during the first quarter of 2020 was 27,575 BOE/d (63% oil), a 6% increase from the average daily oil production during the first quarter of 2019. Our operators received an average of $45.49 per Bbl of oil, $8.94 per Bbl of natural gas liquids and $0.13 per Mcf of natural gas, for an average realized price of $30.62 per BOE. The average realized price of $0.13 per Mcf of natural gas was primarily due to the pricing terms under our operators' natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the first quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.60) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.
During the first quarter of 2020, we estimate that 192 gross (4.6 net 100% royalty interest) horizontal wells, in which we have an average royalty interest of 2.4% were turned to production on our existing acreage position with an average lateral length of 9,306 feet. Of these 192 gross wells, Diamondback is the operator of 78, in which we have an average royalty interest of 3.8%, and the remaining 114 gross wells, in which have an average royalty interest of 1.4%, are operated by third parties. Additionally, during the first quarter of 2020, we acquired 410 net royalty acres for an aggregate purchase price of approximately $63.4 million, which added a further 92 gross (0.6 net 100% royalty interest) producing horizontal wells with an average royalty interest of 0.6%. In total, as of March 31, 2020, we had 2,454 vertical wells and 4,309 horizontal wells producing on our acreage with a combined average net royalty interest of 3.7%.
Despite the dramatic decline in oil prices, there continues to be active development across our asset base and we currently expect our full year 2020 acreage daily production to be between 22,500 to 27,000 Boe/d. Given the recent extreme weakness in commodity prices and forward pricing uncertainty, our current 2020 production guidance does not account for the potential effect of further production curtailments. Near-term activity is expected to be driven primarily by Diamondback's operations. To that end, there are 77 gross horizontal wells operated by Diamondback currently in the process of development on our royalty acreage, in which we expect to own an average 6.6% net royalty interest (5.1 net 100% royalty interest wells). These wells currently in the process of active development include various wells being drilled by the 12 active Diamondback rigs which were on our acreage as of April 22, 2020, in addition to other wells currently waiting to be completed, actively in the process of being completed or waiting to be turned to production. Additionally, based on Diamondback's current completion schedule, we have line-of-sight to a further 50 gross (4.1 net 100% royalty interest) wells for which the process of active development has not yet begun, but for which we have visibility to the potential of future development in coming quarters. There is currently less visibility into third party operators' anticipated activity levels and well completion cadence given the current commodity price environment. Existing permits or active development of our royalty acreage does not ensure that those wells will be turned to production given the current depressed oil prices and tight physical markets. Notwithstanding the foregoing, third parties continue to operate on our asset base. There are 492 gross horizontal wells operated by third parties in the process of active development, in which we expect to own an average 0.9% net royalty interest (4.4 net 100% royalty interest wells). Additionally, there are 379 gross (4.2 net 100% royalty interest) wells operated by third parties that have been permitted but not yet begun the process of active development. In total, as of April 22, 2020, between Diamondback and third party operators, there were 569 (9.5 net 100% royalty interest) wells currently in the process of active development, including 37 active rigs, and a further 429 gross (8.2 net 100% royalty interest) line-of-sight wells which have not yet begun the process of active development. The acquisitions that we closed during the first quarter of 2020 contributed 39 gross (0.2 net 100% royalty interest) horizontal wells in the process of active development out of the total Table of Contents
currently in our portfolio. Further, these recent acquisitions also contributed 18 gross (0.1 net 100% royalty interest) permits out of the total 429 total gross line-of-sight wells for which the process of active development has not yet begun.
Results of Operations The following table summarizes our revenue and expenses and production data for the periods indicated: Three Months Ended March 31, 2020 2019 (in thousands) Operating Results: Operating income: Royalty income $ 76,829 $ 60,428 Lease bonus income 1,622 1,160 Other operating income 241 2 Total operating income 78,692 61,590 Costs and expenses: Production and ad valorem taxes 6,147 3,692 Depletion 24,642 16,199 General and administrative expenses 2,666 1,695 Total costs and expenses 33,455 21,586 Income from operations 45,237 40,004 Other income (expense): Interest expense, net (8,963 ) (4,549 ) Loss on derivative instruments, net (7,942 ) - (Loss) gain on revaluation of investment (10,120 ) 3,592 Other income, net 404 656 Total other expense, net (26,621 ) (301 ) Income before income taxes 18,616 39,703 Provision for (benefit from) income taxes 142,466 (34,608 ) Net (loss) income (123,850 ) 74,311 Net income attributable to non-controlling interest 18,319 40,532 Net (loss) income attributable to Viper Energy Partners LP $ (142,169 ) $ 33,779
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Three Months Ended March 31, 2020 2019 Production Data: Oil (MBbls) 1,587 1,147 Natural gas (MMcf) 2,658 1,872 Natural gas liquids (MBbls) 479 254 Combined volumes (MBOE) 2,509 1,714 Average daily oil volumes (BO/d) 17,441 12,750 Average daily combined volumes (BOE/d) 27,575 19,042 Average sales prices: Oil ($/Bbl) $ 45.49 $ 45.31 Natural gas ($/Mcf)(1) $ 0.13 $ 2.05 Natural gas liquids ($/Bbl) $ 8.94 $ 18.09 Combined ($/BOE) $ 30.62 $ 35.26 Oil, hedged ($/Bbl)(2) $ 45.49 $ 45.31 Natural gas, hedged ($/MMbtu)(2) $ (0.04 ) $ 2.05 Natural gas liquids ($/Bbl)(2) $ 8.94 $ 18.09 Combined price, hedged ($/BOE)(2) $ 30.44 $ 35.26 Average Costs ($/BOE): Production and ad valorem taxes $ 2.45 $ 2.15 General and administrative - cash component 0.91 0.75 Total operating expense - cash $ 3.36 $ 2.90 General and administrative - non-cash component $ 0.15 $ 0.24 Interest expense, net $ 3.57 $ 2.65 Depletion $ 9.82 $ 9.45
(1) The average realized price of $0.13 per Mcf of natural gas was primarily due to the pricing terms under our operators' natural gas delivery contracts, which are generally tied to NYMEX price quoted at Henry Hub. Actual volumetric prices realized from the sale of natural gas, however, differ from the quoted NYMEX price as a result of quality and location differentials. During the first quarter of 2020, natural gas sold at the WAHA Hub in Pecos County, Texas averaged a differential of $(1.60) relative to the NYMEX price quoted at Henry Hub. Our operators may have varying terms under which they sell their natural gas, but we are mostly impacted by location differences resulting from supply and demand imbalances and limited takeaway capacity within the Permian Basin.
(2) Hedged prices reflect the effect of our commodity derivative transactions on our average sales prices. Our calculation of such effects includes gains and losses on cash settlements for commodity derivatives, which we do not designate for hedge accounting. We did not have any derivative contracts prior to February of 2020.
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Comparison of the Three Months Ended March 31, 2020 and 2019
Our royalty income for the three months ended March 31, 2020 and 2019 was $76.8 million and $60.4 million, respectively. Our royalty income is a function of oil, natural gas liquids and natural gas production volumes sold and average prices received for those volumes.
The decrease in average prices received during the three months ended March 31, 2020 as compared to the three months ended March 31, 2019 was partially offset by a 46% increase in combined volumes sold by our operators as compared to the three months ended March 31, 2019.
Production Total net dollar Change in prices volumes(1) effect of change (in thousands) Effect of changes in price: Oil $ 0.19 1,587 $ 294 Natural gas $ (1.92 ) 2,658 (5,109 ) Natural gas liquids $ (9.15 ) 479 (4,383 ) Total income due to change in price $ (9,198 ) Change in production Prior period Total net dollar volumes(1) average prices effect of change (in thousands) Effect of changes in production volumes: Oil 440 $ 45.31 $ 19,919 Natural gas 787 $ 2.05 1,614 Natural gas liquids 225 $ 18.09 4,066 Total income due to change in production volumes 25,599 Total change in income $ 16,401
(1) Production volumes are presented in MBbls for oil and natural gas liquids and MMcf for natural gas.
Lease Bonus Income
Lease bonus income increased by $0.5 million for the three months ended March 31, 2020 as compared to the three months ended March 31, 2019. During the three months ended March 31, 2020, we received $0.3 million in lease bonus payments to extend the term of one lease and $1.3 million for two new leases. During the three months ended March 31, 2019, we received $44,688 in lease bonus payments to extend the term of five leases and $1.1 million for six new leases.
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Production and Ad Valorem Taxes
Production taxes per unit of production for the three months ended March 31, 2020 and 2019 were $1.43 and $1.75, respectively. The decrease in production taxes per unit of production during the three months ended March 31, 2020 was primarily due to a higher percentage increase in production volumes as compared to production taxes. Ad valorem taxes per unit of production for the three months ended March 31, 2020 and 2019 were $1.02 and $0.40, respectively. The increase in ad valorem taxes per unit of production during the three months ended March 31, 2020 was primarily due to an increase in production volumes from wells drilled and acquired in 2019, along with an increase in the valuation of oil and natural gas interests year over year.
Three Months Ended March 31, 2020 2019 Amount Amount (in thousands) Per BOE (in thousands) Per BOE Production taxes $ 3,575 $ 1.43 $ 3,008 $ 1.75 Ad valorem taxes 2,572 1.02 684 0.40 Total production and ad valorem taxes $ 6,147 $ 2.45 $ 3,692 $ 2.15
Depletion expense increased by $8.4 million to $24.6 million for the three months ended March 31, 2020 from $16.2 million for the three months ended March 31, 2019. The increase resulted primarily from higher production levels and an increase in net book value on new reserves added.
General and Administrative Expenses
The general and administrative expenses primarily reflect costs associated with us being a publicly traded limited partnership, unit-based compensation and the amounts reimbursed to our general partner under our partnership agreement. For the three months ended March 31, 2020 and 2019, we incurred general and administrative expenses of $2.7 million and $1.7 million, respectively. The increase of $1.0 million during the three months ended March 31, 2020 was due to an increase in expenses allocated from the General Partner under the Partnership Agreement, an increase in software expenses, bad debt expense and additional professional service fees attributable to acquisitions.
Net Interest Expense
Net interest expense for the three months ended March 31, 2020 and 2019 was $9.0 million and $4.5 million, respectively. The increase of $4.4 million in net interest expense for three months ended March 31, 2020 as compared to 2019 was due to increased borrowings and our senior notes issued in October 2019.
We recorded a loss on derivatives for the three months ended March 31, 2020 of $7.9 million. We had no derivatives during the three months ended March 31, 2019. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. We have not designated our derivative instruments as hedges for accounting purposes. As a result, we mark our derivative instruments to fair value and recognize the cash and non-cash changes in fair value on derivative instruments in our consolidated statements of operations under the line item captioned "Loss on derivative instruments, net."
Provision for (Benefit from) Income Taxes
We recorded income tax expense of $142.5 million and income tax benefit of $34.6 million for the three months ended March 31, 2020 and 2019, respectively. The change in our income tax provision was primarily due to the application of a valuation allowance on the our deferred tax assets during the three months ended March 31, 2020, and the revision during the three months ended March 31, 2019 of estimated deferred taxes recognized as a result of our change in federal income tax status. Total income tax provision for the three months ended March 31, 2020 differed from amounts computed by applying the federal statutory tax rate to pre-tax income for the period primarily due to impact of recording a valuation allowance on our deferred tax assets and net income attributable to the non-controlling interest.
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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. In addition, management uses Adjusted EBITDA to evaluate cash flow available to pay distributions to our common unitholders.
We define Adjusted EBITDA as net income (loss) plus interest expense, net, non-cash unit-based compensation expense, depletion expense, (loss) gain on revaluation of investment, non-cash loss (gain) on derivative instruments and provision for (benefit from) income taxes. Adjusted EBITDA is not a measure of net (loss) income as determined by GAAP. We exclude the items listed above from net (loss) income 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, none of which are components of Adjusted EBITDA.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income, royalty income, cash flow from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Our computations of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies.
The following table presents a reconciliation of Adjusted EBITDA to net income
Three Months Ended March 31, 2020 2019 (In thousands) Net (loss) income $ (123,850 ) $ 74,311 Interest expense, net 8,963 4,549 Non-cash unit-based compensation expense 387 405 Depletion 24,642 16,199 (Loss) gain on revaluation of investment 10,120 (3,592 ) Non-cash loss on derivative instruments, net 7,489 - Provision for (benefit from) income taxes 142,466 (34,608 ) Consolidated Adjusted EBITDA 70,217 57,264 EBITDA attributable to non-controlling interest (40,175 ) (30,708 ) Adjusted EBITDA attributable to Viper Energy Partners LP $ 30,042 $ 26,556
Non-GAAP Financial Measures
Gross oil, natural gas, and natural gas liquids sales and net sales prices
Revenues and gathering and transportation expenses related to production are reported net in our financial statements under GAAP. This impacts the comparability of certain operating metrics, such as per-unit sales prices, as those metrics are prepared in accordance with GAAP using the net presentation for some revenues and the gross presentation for other metrics. In order to provide metrics consistent with management's assessment of our operating results, we have presented both net (GAAP) and gross (non-GAAP) oil, natural gas, and natural gas liquid sales and the gross sales price. The gross sales . . .
May 08, 2020
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