QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 2023
OR
☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF SECURITIES EXCHANGE ACT OF 1934
Commission File Number 001-36505
Viper Energy Partners LP
(Exact Name of Registrant As Specified in Its Charter)
DE
46-5001985
(State or Other Jurisdiction of Incorporation or Organization)
(I.R.S. Employer Identification Number)
500 West Texas Ave.
Suite 100
Midland,TX
79701
(Address of principal executive offices)
(Zip code)
(432) 221-7400
(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Securities Exchange Act of 1934:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Common Units
VNOM
The Nasdaq Stock Market LLC
(NASDAQ Global Select Market)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated Filer
☒
Accelerated Filer
☐
Non-Accelerated Filer
☐
Smaller Reporting Company
☐
Emerging Growth Company
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
As of April 28, 2023, the registrant had outstanding 72,016,622 common units representing limited partner interests and 90,709,946 Class B units representing limited partner interests.
The following is a glossary of certain oil and natural gas terms that are used in this Quarterly Report on Form 10-Q (this “report”):
Argus WTI Midland
Crude oil price index at the Permian Basin.
Basin
A large depression on the earth’s surface in which sediments accumulate.
Bbl or barrel
One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to crude oil or other liquid hydrocarbons.
BO
One barrel of oil.
BO/d
BO per day.
BOE
One barrel of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
BOE/d
BOE per day.
British Thermal Unit or Btu
The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Condensate
Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
Horizontal wells
Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.
MBbls
Thousand barrels of crude oil or other liquid hydrocarbons.
MBOE
One thousand barrels of crude oil equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mcf
One thousand cubic feet of natural gas.
Mineral interests
The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.
MMBtu
One million British Thermal Units.
MMcf
Million cubic feet of natural gas.
Net royalty acres
Net mineral acres multiplied by the average lease royalty interest and other burdens.
Oil and natural gas properties
Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.
Operator
The individual or company responsible for the exploration and/or production of an oil or natural gas well or lease.
Prospect
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
Proved reserves
The estimated quantities of oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Reserves
The estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to the market and all permits and financing required to implement the project. Reserves are not assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reservoir
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or crude oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.
Royalty interest
An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development, which may be subject to expiration.
Various statements contained in this report are “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 our: 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 we have mineral and royalty interests, developmental activity by other operators; reserve estimates and our ability to replace or increase reserves; anticipated benefits of strategic transactions (including acquisitions and divestitures); and plans and objectives of management (including Diamondback’s plans for developing our acreage and our cash distribution policy and repurchases of our common units and/or senior notes) are forward-looking statements. When used in this report, 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 us are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. In particular, the factors discussed in this report and detailed under Part II. Item 1A. Risk Factors, and our Annual Report on Form 10-K for the year ended December 31, 2022, could affect our actual results and cause our actual results to differ materially from expectations, estimates or assumptions expressed, forecasted or implied in such forward-looking statements. Unless the context requires otherwise, references to “we,” “us,” “our” or “the Partnership” are intended to mean the business and operations of the Partnership and the Operating Company.
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 OPEC and Russia affecting the production and pricing of oil, as well as other domestic and global political, economic, or diplomatic developments;
•changes in general economic, business or industry conditions, including changes in foreign currency exchange rates, interest rates, inflation rates, instability in the financial sector and concerns over a potential economic downturn or recession;
•regional supply and demand factors, including delays, curtailment delays or interruptions of production on our mineral and royalty acreage, or governmental orders, rules or regulations that impose production limits on such acreage;
•federal and state legislative and regulatory initiatives relating to hydraulic fracturing, including the effect of existing and future laws and governmental regulations;
•physical and transition risks relating to climate change;
•restrictions on the use of water, including limits on the use of produced water by our operators and a moratorium on new produced water well permits recently imposed by the Texas Railroad Commission in an effort to control induced seismicity in the Permian Basin;
•significant declines in prices for oil, natural gas, or natural gas liquids, which could require recognition of significant impairment charges;
•changes in U.S. energy, environmental, monetary and trade policies;
•conditions in the capital, financial and credit markets, including the availability and pricing of capital for drilling and development by our operators and environmental and social responsibility projects undertaken by Diamondback and our other operators;
•changes in availability or cost of rigs, equipment, raw materials, supplies and oilfield services impacting our operators;
•changes in safety, health, environmental, tax, and other regulations or requirements impacting us or our operators (including those addressing air emissions, water management, or the impact of global climate change);
•security threats, including cybersecurity threats and disruptions to our business from breaches of our information technology systems, or from breaches of information technology systems of our operators or third parties with whom we transact business;
•lack of, or disruption in, access to adequate and reliable transportation, processing, storage, and other facilities impacting our operators;
•severe weather conditions;
•acts of war or terrorist acts and the governmental or military response thereto;
•changes in the financial strength of counterparties to the credit agreement and hedging contracts of our operating subsidiary;
•changes in our credit rating; and
•other risks and factors disclosed in this report.
In light of these factors, the events anticipated by our forward-looking statements may not occur at the time anticipated or at all. Moreover, new risks emerge from time to time. We cannot predict all risks, nor can we assess the impact of all factors on our 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 we may make. Accordingly, you should not place undue reliance on any forward-looking statements made in this report. All forward-looking statements speak only as of the date of this report or, if earlier, as of the date they were made. We do not intend to, and disclaim any obligation to, update or revise any forward-looking statements unless required by applicable law.
Royalty income receivable (net of allowance for credit losses)
83,038
81,657
Royalty income receivable—related party
36,324
6,260
Derivative instruments
1,357
9,328
Other current assets
3,445
3,196
Total current assets
133,270
118,620
Property:
Oil and natural gas interests, full cost method of accounting ($1,262,269 and $1,297,221 excluded from depletion at March 31, 2023 and December 31, 2022, respectively)
3,582,601
3,464,819
Land
5,688
5,688
Accumulated depletion and impairment
(751,221)
(720,234)
Property, net
2,837,068
2,750,273
Derivative instruments
—
442
Deferred income taxes (net of allowances)
49,228
49,656
Other assets
170
1,382
Total assets
$
3,019,736
$
2,920,373
Liabilities and Unitholders’ Equity
Current liabilities:
Accounts payable
$
436
$
1,129
Accounts payable—related party
—
306
Accrued liabilities
17,759
19,600
Derivative instruments
2,099
—
Income taxes payable
9,477
911
Total current liabilities
29,771
21,946
Long-term debt, net
695,154
576,895
Derivative instruments
2,383
7
Total liabilities
727,308
598,848
Commitments and contingencies (Note 12)
Unitholders’ equity:
General Partner
629
649
Common units (72,118,622 units issued and outstanding as of March 31, 2023 and 73,229,645 units issued and outstanding as of December 31, 2022)
666,259
689,178
Class B units (90,709,946 units issued and outstanding as of March 31, 2023 and December 31, 2022)
807
832
Total Viper Energy Partners LP unitholders’ equity
667,695
690,659
Non-controlling interest
1,624,733
1,630,866
Total equity
2,292,428
2,321,525
Total liabilities and unitholders’ equity
$
3,019,736
$
2,920,373
See accompanying notes to condensed consolidated financial statements.
Condensed Notes to Consolidated Financial Statements
(Unaudited)
1. ORGANIZATION AND BASIS OF PRESENTATION
Organization
Viper Energy Partners LP (the “Partnership”) is a publicly traded Delaware limited partnership focused on owning and acquiring mineral interests and royalty interests in oil and natural gas properties primarily in the Permian Basin.
As of March 31, 2023, Viper Energy Partners GP LLC (the “General Partner”) held a 100% general partner interest in the Partnership and Diamondback Energy, Inc. (“Diamondback”) beneficially owned approximately 56% of the Partnership’s total limited partner units outstanding. Diamondback owns and controls the General Partner.
Basis of Presentation
The accompanying condensed consolidated financial statements and related notes thereto were prepared in accordance with GAAP. All material intercompany balances and transactions have been eliminated upon consolidation. We report our operations in one reportable segment.
These condensed consolidated financial statements have been prepared by the Partnership without audit, pursuant to the rules and regulations of the SEC. They reflect all adjustments that are, in the opinion of management, necessary for a fair statement of the results for interim periods, on a basis consistent with the annual audited financial statements. All such adjustments are of a normal recurring nature. Certain information, accounting policies and footnote disclosures normally included in financial statements prepared in accordance with GAAP have been omitted pursuant to SEC rules and regulations, although the Partnership believes the disclosures are adequate to make the information presented not misleading. This report should be read in conjunction with the Partnership’s most recent Annual Report on Form 10–K for the fiscal year ended December 31, 2022, which contains a summary of the Partnership’s significant accounting policies and other disclosures.
Reclassifications
Certain prior period amounts have been reclassified to conform to the current period financial statement presentation. These reclassifications had no effect on the previously reported total assets, total liabilities, unitholders’ equity, results of operations or cash flows.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Certain amounts included in or affecting the Partnership’s financial statements and related disclosures must be estimated by management, requiring certain assumptions to be made with respect to values or conditions that cannot be known with certainty at the time the financial statements are prepared. These estimates and assumptions affect the amounts the Partnership reports for assets and liabilities and the Partnership’s disclosure of contingent assets and liabilities as of the date of the financial statements.
Making accurate estimates and assumptions is particularly difficult in the oil and natural gas industry given the challenges resulting from volatility in oil and natural gas prices. For instance, the war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, and measures to combat persistent inflation and instability in the financial sector have contributed to recent pricing and economic volatility. The financial results of companies in the oil and natural gas industry have been and may continue to be impacted materially as a result of changing market conditions. Such circumstances generally increase uncertainty in the Partnership’s accounting estimates, particularly those involving financial forecasts.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each particular circumstance. Nevertheless, actual results may differ significantly from the Partnership’s estimates. Any effects on the Partnership’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Significant items subject to such estimates and assumptions include estimates of proved oil and natural gas reserves and related present value estimates of future net cash flows therefrom, the carrying value of oil and natural gas interests, estimates of third party operated royalty income related to expected sales volumes and prices, the recoverability of costs of unevaluated properties, the fair value determination of assets and liabilities, including those acquired by the Partnership, fair value estimates of commodity derivatives and estimates of income taxes, including deferred tax valuation allowances.
Related Party Transactions
Royalty Income Receivable
As of March 31, 2023, Diamondback, either directly or through its consolidated subsidiaries, owed the Partnership $36.3 million compared to $6.3 million at December 31, 2022 for royalty income received from third parties for the Partnership’s production, which had not yet been remitted to the Partnership.
Lease Bonus Income
During the three months ended March 31, 2023 and 2022, Diamondback, either directly or through its consolidated subsidiaries, paid the Partnership $7.1 million and $6.3 million of lease bonus income primarily related to lease extensions and new leases in the Midland Basin.
See Note 4—Acquisitions and Divestitures for significant related party acquisitions of oil and natural gas interests. All other significant related party transactions with Diamondback or its affiliates have been stated on the face of the consolidated financial statements included elsewhere in this report as of March 31, 2023 and for the three months ended March 31, 2023 and 2022.
Accrued Liabilities
Accrued liabilities consist of the following:
March 31,
December 31,
2023
2022
(In thousands)
Interest payable
$
10,405
$
3,972
Ad valorem taxes payable
5,146
12,492
Derivatives instruments payable
699
1,684
Other
1,509
1,452
Total accrued liabilities
$
17,759
$
19,600
Recent Accounting Pronouncements
Recently Adopted Pronouncements
There are no recently adopted pronouncements.
Accounting Pronouncements Not Yet Adopted
The Partnership considers the applicability and impact of all ASUs. There are no recent accounting pronouncements not yet adopted that are expected to have a material effect on the Partnership upon adoption, as applicable.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
3. REVENUE FROM CONTRACTS WITH CUSTOMERS
Royalty income represents the right to receive revenues from oil, natural gas and natural gas liquids sales obtained by the operator of the wells in which the Partnership owns a royalty interest. Royalty income is recognized at the point control of the product is transferred to the purchaser at the wellhead or at the gas processing facility based on the Partnership’s percentage ownership share of the revenue, net of any deductions for gathering and transportation. Virtually all of the pricing provisions in the Partnership’s contracts are tied to a market index.
The following table disaggregates the Partnership’s total royalty income by product type:
Three Months Ended March 31,
2023
2022
(In thousands)
Oil income
$
136,619
$
155,051
Natural gas income
8,991
15,190
Natural gas liquids income
15,475
22,848
Total royalty income
$
161,085
$
193,089
4. ACQUISITIONS AND DIVESTITURES
2023 Activity
Drop Down Transaction
On March 8, 2023, the Partnership completed the acquisition of certain mineral and royalty interests from subsidiaries of Diamondback for approximately $75.1 million in cash, subject to customary post-closing adjustments for net title benefits (the ‘‘Drop Down’’). The mineral and royalty interests acquired in the Drop Down represent approximately 660 net royalty acres in Ward County in the Southern Delaware Basin, 100% of which are operated by Diamondback, and have an average net royalty interest of approximately 7.2% and current production of approximately 300 BO/d, approximately 72% of which is from oil. The Partnership funded the Drop Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control with the properties acquired recorded at Diamondback’s historical carrying value in the Partnership’s condensed consolidated balance sheet at March 31, 2023. The historical carrying value of the properties approximated the Drop Down purchase price.
Other Acquisitions
Additionally in the first quarter of 2023, the Partnership acquired, in individually insignificant transactions from unrelated third-party sellers, mineral and royalty interests representing 159 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.7 million, subject to customary post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.
2022 Activity
Acquisitions
During the year ended December 31, 2022, in individually insignificant transactions, the Partnership acquired from unrelated third-party sellers mineral and royalty interests representing 375 net royalty acres in the Permian Basin for an aggregate net purchase price of approximately $65.9 million, including certain customary post-closing adjustments. The Partnership funded these acquisitions with cash on hand and borrowings under the Operating Company’s revolving credit facility.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Divestitures
In the first quarter of 2022, the Partnership divested 325 net royalty acres of third party operated acreage located entirely in Upton and Reagan counties in the Midland Basin for an aggregate net sales price of $29.3 million, including customary closing adjustments.
In the third quarter of 2022, the Partnership divested 93 net royalty acres of third party operated acreage located entirely in Loving county in the Delaware Basin for an aggregate net sales price of $29.9 million, including customary closing adjustments.
In the fourth quarter of 2022, the Partnership divested its entire position in the Eagle Ford Shale consisting of 681 net royalty acres of third party operated acreage for an aggregate net sales price of $53.8 million, including customary closing adjustments.
5. OIL AND NATURAL GAS INTERESTS
Oil and natural gas interests include the following:
March 31,
December 31,
2023
2022
(In thousands)
Oil and natural gas interests:
Subject to depletion
$
2,320,332
$
2,167,598
Not subject to depletion
1,262,269
1,297,221
Gross oil and natural gas interests
3,582,601
3,464,819
Accumulated depletion and impairment
(751,221)
(720,234)
Oil and natural gas interests, net
2,831,380
2,744,585
Land
5,688
5,688
Property, net of accumulated depletion and impairment
$
2,837,068
$
2,750,273
As of March 31, 2023 and December 31, 2022, the Partnership had mineral and royalty interests representing 27,134 and 26,315 net royalty acres, respectively.
No impairment expense was recorded on the Partnership’s oil and natural gas interests for the three months ended March 31, 2023 and 2022 based on the results of the respective quarterly ceiling tests. In addition to commodity prices, the Partnership’s production rates, levels of proved reserves, transfers of unevaluated properties and other factors will determine its actual ceiling test limitations and impairment analysis in future periods. If the trailing 12-month commodity prices decline as compared to the commodity prices used in prior quarters, the Partnership may have material write-downs in subsequent quarters.
6. DEBT
Long-term debt consisted of the following as of the dates indicated:
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The Operating Company’s Revolving Credit Facility
The Operating Company’s credit agreement, as amended to date, provides for a revolving credit facility in the maximum credit amount of $2.0 billion and a borrowing base of $580.0 million based on the Operating Company’s oil and natural gas reserves and other factors. The borrowing base is scheduled to be redetermined semi-annually in May and November. As of March 31, 2023, the Operating Company had elected a commitment amount of $500.0 million, with $270.0 million of outstanding borrowings and $230.0 million available for future borrowings. During the three months ended March 31, 2023 and 2022, the weighted average interest rates on the Operating Company’s revolving credit facility were6.10% and 2.58%, respectively. The revolving credit facility will mature on June 2, 2025.
As of March 31, 2023, the Operating Company was in compliance with the financial maintenance covenants under its credit agreement.
7. UNITHOLDERS’ EQUITY AND DISTRIBUTIONS
The Partnership has General Partner and limited partner units. At March 31, 2023, the Partnership had a total of 72,118,622 common units issued and outstanding and 90,709,946 Class B units issued and outstanding, of which 731,500 common units and 90,709,946 Class B units were beneficially owned by Diamondback, representing approximately 56% of the Partnership’s total units outstanding. At March 31, 2023, Diamondback also beneficially owns 90,709,946 Operating Company units, representing a 56% non-controlling ownership interest in the Operating Company. The Operating Company units and the Partnership’s Class B units beneficially owned by Diamondback are exchangeable from time to time for the Partnership’s common units (that is, one Operating Company unit and one Partnership Class B unit, together, will be exchangeable for one Partnership common unit).
Common Unit Repurchase Program
The board of directors of the Partnership’s General Partner has approved a common unit repurchase program to acquire up to $750.0 million of the Partnership’s outstanding common units, excluding excise tax, over an indefinite period of time. The Partnership intends to purchase common units under the repurchase program opportunistically with funds from cash on hand, free cash flow from operations and potential liquidity events such as the sale of assets. This repurchase program may be suspended from time to time, modified, extended or discontinued by the board of directors of the Partnership’s General Partner at any time. During the three months ended March 31, 2023 and 2022, the Partnership repurchased approximately $32.7 million, excluding excise tax, and $39.3 million of common units under the repurchase program, respectively. Repurchases for the three months ended March 31, 2022 include approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction in the first quarter of 2022. As of March 31, 2023, $496.7 million remains available under the repurchase program, excluding excise tax.
Cash Distributions on Common Units
Effective with the Partnership’s distribution payable for the third quarter of 2022, the board of directors of the General Partner approved a distribution policy consisting of a base and variable distribution, that takes into account capital returned to unitholders via our common unit repurchase program. For a detailed description of the Partnership’s and the Operating Company’s distribution policy, see Note 7—Unitholders’ Equity and Distributions—Cash Distributions in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2022.
The percentage of cash available for distribution pursuant to the distribution policy may change quarterly to enable the Operating Company to retain cash flow to help strengthen the Partnership’s balance sheet while also expanding the return of capital program through the Partnership’s common unit repurchase program. The Partnership is not required to pay distributions to its common unitholders on a quarterly or other basis.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The following table presents information regarding cash distributions approved by the board of directors of the General Partner for the periods presented (in thousands, except for per share amounts):
Period
Amount per Operating Company Unit
Operating Company Distributions to Diamondback
Amount per Common Unit
Distributions to Common Unitholders(1)
Declaration Date
Unitholder Record Date
Payment Date
Q4 2022
$
0.54
$
48,983
$
0.49
$
35,683
February 15, 2023
March 3, 2023
March 10, 2023
(1)Includes amounts paid to Diamondback for the 731,500 common units beneficially owned by Diamondback and distribution equivalent rights payments.
Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 60 days after the end of each quarter.
Change in Ownership of Consolidated Subsidiaries
Non-controlling interest in the accompanying condensed consolidated financial statements represents Diamondback’s ownership in the net assets of the Operating Company. Diamondback’s relative ownership interest in the Operating Company can change due to the Partnership’s public offerings, issuance of units for acquisitions, issuance of unit-based compensation, repurchases of common units and distribution equivalent rights paid on the Partnership’s units. These changes in ownership percentage and the disproportionate allocation of net income (loss) to Diamondback discussed belowresult in adjustments to non-controlling interest and common unitholder equity, tax effected, but do not impact earnings. The following table summarizes the changes in common unitholder equity due to changes in ownership interest during the period:
Three Months Ended March 31,
2023
2022
(In thousands)
Net income (loss) attributable to the Partnership
$
33,967
$
16,605
Change in ownership of consolidated subsidiaries
11,449
14,195
Change from net income (loss) attributable to the Partnership's unitholders and transfers to non-controlling interest
$
45,416
$
30,800
8. EARNINGS PER COMMON UNIT
The net income (loss) per common unit on the condensed consolidated statements of operations is based on the net income (loss) attributable to the Partnership’s common units for the three months ended March 31, 2023 and 2022. The Partnership’s net income (loss) is allocated wholly to the common units, as the General Partner does not have an economic interest.
Basic and diluted earnings per common unit is calculated using the two-class method. The two class method is an earnings allocation proportional to the respective ownership among holders of common units and participating securities. Basic net income (loss) per common unit is calculated by dividing net income (loss) by the weighted-average number of common units outstanding during the period. Diluted net income (loss) per common unit gives effect, when applicable, to unvested common units granted under the LTIP.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
A reconciliation of the components of basic and diluted earnings per common unit is presented in the table below:
Three Months Ended March 31,
2023
2022
(In thousands, except per unit amounts)
Net income (loss) attributable to the period
$
33,967
$
16,605
Less: distributed and undistributed earnings allocated to participating securities(1)
72
64
Net income (loss) attributable to common unitholders
$
33,895
$
16,541
Weighted average common units outstanding:
Basic weighted average common units outstanding
72,732
77,106
Effect of dilutive securities:
Potential common units issuable(2)
83
108
Diluted weighted average common units outstanding
72,815
77,214
Net income (loss) per common unit, basic
$
0.47
$
0.22
Net income (loss) per common unit, diluted
$
0.47
$
0.22
(1) Unvested restricted stock units that contain non-forfeitable distribution equivalent rights granted are considered participating securities and therefore are included in the earnings per share calculation pursuant to the two-class method.
(2) For the three months ended March 31, 2023 and 2022, there were no potential common units excluded from the computation of diluted earnings per common unit because their inclusion would have been anti-dilutive.
9. INCOME TAXES
The following table provides the Partnership’s provision for (benefit from) income taxes and the effective income tax rate for the dates indicated:
Three Months Ended March 31,
2023
2022
(In thousands, except for tax rate)
Provision for (benefit from) income taxes
$
9,406
$
2,630
Effective tax rate
9.6
%
2.0
%
The Partnership’s effective income tax rate for the three months ended March 31, 2023 differed from the amount computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest. The Partnership’s effective income tax rate for the three months ended March 31, 2022 differed from the amount computed by applying the United States federal statutory tax rate to pre-tax income for the period primarily due to net income attributable to the non-controlling interest and the impact of maintaining a valuation allowance on the Partnership’s deferred tax assets.
As of March 31, 2023, the Partnership maintained a partial valuation allowance against its deferred tax assets considered not more likely than not to be realized, based on its assessment of all available evidence, both positive and negative, as required by applicable accounting standards.
As of March 31, 2022, the Partnership had a full valuation allowance against its deferred tax assets, based on its assessment of all available evidence, both positive and negative, supporting realizability of the Partnership’s deferred tax assets.
The Inflation Reduction Act of 2022 (“IRA”) was enacted on August 16, 2022, which imposes an excise tax of 1% on the fair market value of certain public company stock/unit repurchases for tax years beginning after December 31, 2022, and included several other provisions applicable to U.S. income taxes for corporations. The Partnership’s excise tax during the three months ended March 31, 2023 was immaterial and is recognized as part of the cost basis of the units repurchased.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
10. DERIVATIVES
All derivative financial instruments are recorded at fair value. The Partnership has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the cash and non-cash changes in fair value in the condensed consolidated statements of operations under the caption “Gain (loss) on derivative instruments, net.”
Commodity Contracts
The Partnership historically has used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of its royalty income. At March 31, 2023, the Partnership has put options and fixed price basis swaps outstanding.
The Partnership’s derivative contracts are based upon reported settlement prices on commodity exchanges, with put contracts for oil based on New York Mercantile Exchange West Texas Intermediate pricing (“Cushing WTI”) and fixed price basis swaps for oil based on the spread between the Cushing WTI crude oil price and the Midland WTI crude oil price. The Partnership’s fixed price basis swaps for natural gas are for the spread between the Waha Hub natural gas price and the New York Mercantile Exchange Henry Hub natural gas price. The weighted average differential represents the amount of reduction to the Cushing WTI oil price and the Waha Hub natural gas price for the notional volumes covered by the basis swap contracts.
By using derivative instruments to economically hedge exposure to changes in commodity prices, the Partnership exposes itself to credit risk and market risk. Credit risk is the failure of the counterparty to perform under the terms of the derivative contract. When the fair value of a derivative contract is positive, the counterparty owes the Partnership, which creates credit risk. The Partnership’s counterparties are all participants in the amended and restated credit agreement, which is secured by substantially all of the assets of the Operating Company; therefore, the Partnership is not required to post any collateral. The Partnership’s counterparties have been determined to have an acceptable credit risk; therefore, the Partnership does not require collateral from its counterparties.
As of March 31, 2023, the Partnership had the following outstanding derivative contracts. When aggregating multiple contracts, the weighted average contract price is disclosed.
Swaps
Puts
Settlement Month
Settlement Year
Type of Contract
Bbls/Mcf Per Day
Index
Weighted Average Differential
Strike Price
Deferred Premium
OIL
Apr. - Jun.
2023
Puts
12,000
WTI Cushing
$—
$55.00
$1.82
Jul. - Sep.
2023
Puts
12,000
WTI Cushing
$—
$55.00
$1.80
Oct. - Dec.
2023
Puts
4,000
WTI Cushing
$—
$55.00
$1.86
Apr. - Dec.
2023
Basis Swaps
4,000
Argus WTI Midland
$1.05
$—
$—
NATURAL GAS
Apr. - Dec.
2023
Basis Swaps
30,000
Waha Hub
$(1.33)
$—
$—
Jan. - Dec.
2024
Basis Swaps
30,000
Waha Hub
$(1.20)
$—
$—
Balance Sheet Offsetting of Derivative Assets and Liabilities
The fair value of derivative instruments is generally determined using established index prices and other sources which are based upon, among other things, futures prices and time to maturity. These fair values are recorded by netting asset and liability positions, including any deferred premiums, that are with the same counterparty and are subject to contractual terms which provide for net settlement. See Note 11—Fair Value Measurements for further details.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
Gains and Losses on Derivative Instruments
The following table summarizes the gains and losses on derivative instruments included in the condensed consolidated statements of operations and the net cash receipts (payments) on derivatives for the periods presented:
Three Months Ended March 31,
2023
2022
(In thousands)
Gain (loss) on derivative instruments
$
(15,103)
$
(18,359)
Net cash receipts (payments) on derivatives(1)
$
(2,215)
$
(10,264)
(1)The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.
11. FAIR VALUE MEASUREMENTS
Assets and Liabilities Measured at Fair Value on a Recurring Basis
As discussed in Note 11—Fair Value Measurements in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2022, certain assets and liabilities are reported at fair value on a recurring basis on the Partnership’s condensed consolidated balance sheets, including the Partnership’s derivative instruments. The fair values of the Partnership’s derivative contracts are measured internally using established commodity futures price strips for the underlying commodity provided by a reputable third party, the contracted notional volumes, and time to maturity. These valuations are Level 2 inputs in the fair value hierarchy. The net amounts are classified as current or noncurrent based on their anticipated settlement dates.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The following table provides (i) fair value measurement information for financial assets and liabilities measured at fair value on a recurring basis, (ii) the gross amounts of recognized derivative assets and liabilities, (iii) the amounts offset under master netting arrangements with counterparties and (iv) the resulting net amounts presented in the Partnership’s condensed consolidated balance sheets as of March 31, 2023 and December 31, 2022:
As of March 31, 2023
Level 1
Level 2
Level 3
Total Gross Fair Value
Gross Amounts Offset in Balance Sheet
Net Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments
$
—
$
5,072
$
—
$
5,072
$
(3,715)
$
1,357
Liabilities:
Current:
Derivative instruments
$
—
$
5,814
$
—
$
5,814
$
(3,715)
$
2,099
Non-current:
Derivative instruments
$
—
$
2,383
$
—
$
2,383
$
—
$
2,383
As of December 31, 2022
Level 1
Level 2
Level 3
Total Gross Fair Value
Gross Amounts Offset in Balance Sheet
Net Fair Value Presented in Balance Sheet
(In thousands)
Assets:
Current:
Derivative instruments
$
—
$
13,296
$
—
$
13,296
$
(3,968)
$
9,328
Non-current:
Derivative instruments
—
1,911
—
1,911
(1,469)
442
Liabilities:
Current:
Derivative instruments
$
—
$
3,968
$
—
$
3,968
$
(3,968)
$
—
Non-current:
Derivative instruments
$
—
$
1,476
$
—
$
1,476
$
(1,469)
$
7
Assets and Liabilities Not Recorded at Fair Value
The following table provides the fair value of financial instruments that are not recorded at fair value in the condensed consolidated balance sheets:
March 31, 2023
December 31, 2022
Carrying Value
Fair Value
Carrying Value
Fair Value
(In thousands)
Debt:
Revolving credit facility
$
270,000
$
270,000
$
152,000
$
152,000
5.375% senior notes due 2027(1)
$
425,154
$
416,041
$
424,895
$
411,634
(1) The carrying value includes associated deferred loan costs and any discount.
Condensed Notes to Consolidated Financial Statements - (Continued)
(Unaudited)
The fair value of the Operating Company’s revolving credit facility approximates the carrying value based on borrowing rates available to the Partnership for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy. The fair value of the Notes was determined using the March 31, 2023 quoted market price, a Level 1 classification in the fair value hierarchy.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are measured at fair value on a nonrecurring basis in certain circumstances. These assets and liabilities can include mineral and royalty interests acquired in asset acquisitions and subsequent write-downs of our proved oil and natural gas interests to fair value when they are impaired or held for sale.
Fair Value of Financial Assets
The Partnership has other financial instruments consisting of cash and cash equivalents, royalty income receivable, other current assets, accounts payable, accrued liabilities and income taxes payable. The carrying value of these instruments approximate their fair value because of the short-term nature of the instruments.
12. COMMITMENTS AND CONTINGENCIES
The Partnership is a party to various routine legal proceedings, disputes and claims from time to time arising in the ordinary course of its business. While the ultimate outcome of the pending proceedings, disputes or claims, and any resulting impact on the Partnership, cannot be predicted with certainty, the Partnership’s management believes that none of these matters, if ultimately decided adversely, will have a material adverse effect on the Partnership’s financial condition, results of operations or cash flows. The Partnership’s assessment is based on information known about the pending matters and its experience in contesting, litigating and settling similar matters. Actual outcomes could differ materially from the Partnership’s assessment. The Partnership records reserves for contingencies related to outstanding legal proceedings, disputes or claims when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
13. SUBSEQUENT EVENTS
Cash Distribution
On April 26, 2023, the board of directors of the General Partner approved a cash distribution for the first quarter of 2023 of $0.33 per common unit, payable on May 18, 2023, to eligible unitholders of record at the close of business on May 11, 2023. The distribution consists of a base quarterly distribution of $0.25 per common unit and a variable quarterly distribution of $0.08 per common unit.
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 condensed 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, 2022. 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.”
Overview
We are a publicly traded Delaware limited partnership formed by Diamondback to own and acquire mineral and royalty interests in oil and natural gas properties primarily in the Permian Basin. We operate in one reportable segment. Since May 10, 2018, we have been treated as a corporation for U.S. federal income tax purposes.
Recent Developments
Commodity Prices
Prices for oil, natural gas and natural gas liquids are determined primarily by prevailing market conditions. Regional and worldwide economic activity, including any economic downturn or recession that has occurred or may occur in the future, extreme weather conditions and other substantially variable factors influence market conditions for these products. These factors are beyond our control and are difficult to predict. During 2022 and the first quarter of 2023, NYMEX WTI, has ranged from $66.74 to $123.70 per Bbl, and the NYMEX Henry Hub price of natural gas has ranged from $1.99 to $9.68 per MMBtu, with seven-year highs reached in 2022. The war in Ukraine, the COVID-19 pandemic, rising interest rates, global supply chain disruptions, concerns about a potential economic downturn or recession, measures to combat persistent inflation and instability in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout 2023. Additionally, OPEC and its non-OPEC allies, known collectively as OPEC+, continues to meet regularly to evaluate the state of global oil supply, demand and inventory levels.
Acquisitions Update
Drop Down Transaction
On March 8, 2023, we acquired certain mineral and royalty interests from subsidiaries of Diamondback for approximately $75.1 million in cash, subject to customary post-closing adjustments. We funded the Drop Down through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility. The Drop Down was accounted for as a transaction between entities under common control.
Other Acquisitions
Additionally in the first quarter of 2023, in individually insignificant transactions, we acquired from unrelated third-party sellers, mineral and royalty interests representing 159 net royalty acres in the Permian Basin for an aggregate purchase price of approximately $40.7 million, subject to customary post-closing adjustments. We funded these acquisitions through a combination of cash on hand and borrowings under the Operating Company’s revolving credit facility.
As a result of these 2023 acquisitions, our footprint of mineral and royalty interests totaled 27,134 net royalty acres, approximately 57% of which are operated by Diamondback, as of March 31, 2023.
See Note 4—Acquisitions and Divestitures of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.
Average oil production per day during the first quarter of 2023 was the highest in the Partnership’s history. There are currently 38 rigs operating on our mineral and royalty acreage, nine of which are operated by Diamondback. The Drop Down provides a high NRI exposure to Diamondback’s expected development plan in the Southern Delaware Basin over the next several years and is expected to enhance our growth profile as well. As a result of the Drop Down and continued outperformance of our production goals, we have increased our full year 2023 production guidance by approximately 12% compared to 2022, which is a two percent increase at the midpoint from our guidance published in February 2023.
The following table summarizes our gross well information as of the dates indicated:
Diamondback Operated
Third Party Operated
Total
Horizontal wells turned to production (first quarter 2023)(1):
Gross wells
50
191
241
Net 100% royalty interest wells
3.2
2.8
6.0
Average percent net royalty interest
6.4
%
1.4
%
2.5
%
Horizontal producing well count (as of April 13, 2023):
Gross wells
1,633
3,929
5,562
Net 100% royalty interest wells
119.4
63.1
182.5
Average percent net royalty interest
7.3
%
1.6
%
3.3
%
Horizontal active development well count (as of April 13, 2023)(2):
Gross wells
143
345
488
Net 100% royalty interest wells
9.1
3.2
12.3
Average percent net royalty interest
6.4
%
0.9
%
2.5
%
Line of sight wells (as of April 13, 2023)(3):
Gross wells
177
276
453
Net 100% royalty interest wells
8.2
4.1
12.3
Average percent net royalty interest
4.7
%
1.5
%
2.7
%
(1) Average lateral length of 10,384.
(2) The total 488 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.
(3) The total 453 gross line-of-sight wells are those that are not currently in the process of active development, but for which we have 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 our royalty acreage does not ensure that those wells will be turned to production given the volatility in oil prices.
The following table summarizes our production data, average sales prices and average costs for the periods indicated:
Three Months Ended
March 31, 2023
December 31, 2022
Production data:
Oil (MBbls)
1,810
1,838
Natural gas (MMcf)
4,224
4,155
Natural gas liquids (MBbls)
633
683
Combined volumes (MBOE)(1)
3,147
3,214
Average daily oil volumes (BO/d)
20,111
19,978
Average daily combined volumes (BOE/d)
34,967
34,935
Average sales prices:
Oil ($/Bbl)
$
75.48
$
83.30
Natural gas ($/Mcf)
$
2.13
$
3.74
Natural gas liquids ($/Bbl)
$
24.45
$
25.65
Combined ($/BOE)(2)
$
51.19
$
57.92
Oil, hedged ($/Bbl)(3)
$
74.30
$
82.71
Natural gas, hedged ($/Mcf)(3)
$
2.11
$
3.03
Natural gas liquids ($/Bbl)(3)
$
24.45
$
25.65
Combined price, hedged ($/BOE)(3)
$
50.48
$
56.66
Average costs ($/BOE):
Production and ad valorem taxes
$
4.10
$
3.37
General and administrative - cash component(4)
0.76
0.70
Total operating expense - cash
$
4.86
$
4.07
General and administrative - non-cash unit compensation expense
$
0.12
$
0.10
Interest expense, net
$
3.08
$
3.19
Depletion
$
9.85
$
9.72
(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.
Royalty Income
Our royalty income is a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes.
Royalty income decreased $25.1 million during the first quarter of 2023 compared to the fourth quarter of 2022. Changes in average pricing contributed approximately $21.7 million of the total decrease due primarily to lower average oil prices, natural gas prices and to a lesser extent, natural gas liquids prices received for our production in the first quarter of 2023. The remaining decrease of $3.4 million in royalty income is due to a 2% decline in production in the first quarter of 2023 compared to the fourth quarter of 2022. This production decline resulted from divesting our entire position in Eagle Ford Shale in late fourth quarter of 2022 and having two fewer days of production in the first quarter of 2023 compared to the fourth quarter of 2022.
Lease bonus income from Diamondback decreased $9.6 million due primarily to receiving payment for one lease in the first quarter of 2023 compared to receiving an additional one-time lease ratification payment of $16.4 million from Diamondback during the fourth quarter of 2022.
Production and Ad Valorem Taxes
The following table presents production and ad valorem taxes for the three months ended March 31, 2023 and December 31, 2022:
Three Months Ended
March 31, 2023
December 31, 2022
Amount (In thousands)
Per BOE
Percentage of Royalty Income
Amount (In thousands)
Per BOE
Percentage of Royalty Income
Production taxes
$
8,177
$
2.60
5.1
%
$
9,373
$
2.92
5.0
%
Ad valorem taxes
4,710
1.50
2.9
1,452
0.45
0.8
Total production and ad valorem taxes
$
12,887
$
4.10
8.0
%
$
10,825
$
3.37
5.8
%
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the first quarter of 2023 were consistent with the fourth quarter of 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in the first quarter of 2023 compared to the fourth quarter of 2022 was primarily due to the fourth quarter of 2022 including $2.9 million in reductions to the full year 2022 accrual for ad valorem taxes to reflect actual tax assessments received. The remaining increase in ad valorem taxes is primarily due to higher valuations assigned to our oil and natural gas interests period over period driven by higher average commodity prices and royalty income in 2022.
Derivative Instruments
The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:
Three Months Ended
March 31, 2023
December 31, 2022
(In thousands)
Gain (loss) on derivative instruments
$
(15,103)
$
1,228
Net cash receipts (payments) on derivatives
$
(2,215)
$
(4,027)
We recorded a loss on our derivative instruments for the first quarter of 2023, compared to a gain for the fourth quarter of 2022. This change is primarily due to a decrease in the basis spread on our outstanding natural gas basis swaps at March 31, 2023 compared to December 31, 2022. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. See Note 10—Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our open contracts at March 31, 2023.
Provision for (Benefit from) Income Taxes
The $4.5 million increase in income tax expense for the first quarter of 2023 compared to the fourth quarter of 2022 is primarily due to the increase in pre-tax income attributable to the Partnership as a result of the expiration of the special income allocation at December 31, 2022. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.
Net Income (Loss) Attributable to Non-controlling Interest
The $69.2 million decrease in net income attributable to non-controlling interest for the first quarter of 2023 compared to the fourth quarter of 2022 is primarily due to the expiration of the special income allocation whereby special allocations of the Operating Company’s income and gains over losses and deductions (but before depletion) were made to Diamondback through December 31, 2022.
The following table summarizes our production data, average sales prices and average costs for the periods indicated:
Three Months Ended March 31,
2023
2022
Production data:
Oil (MBbls)
1,810
1,633
Natural gas (MMcf)
4,224
3,729
Natural gas liquids (MBbls)
633
586
Combined volumes (MBOE)(1)
3,147
2,841
Average daily oil volumes (BO/d)
20,111
18,144
Average daily combined volumes (BOE/d)
34,967
31,567
Average sales prices:
Oil ($/Bbl)
$
75.48
$
94.95
Natural gas ($/Mcf)
$
2.13
$
4.07
Natural gas liquids ($/Bbl)
$
24.45
$
38.99
Combined ($/BOE)(2)
$
51.19
$
67.97
Oil, hedged ($/Bbl)(3)
$
74.30
$
92.05
Natural gas, hedged ($/Mcf)(3)
$
2.11
$
3.71
Natural gas liquids ($/Bbl)(3)
$
24.45
$
38.99
Combined price, hedged ($/BOE)(3)
$
50.48
$
65.82
Average costs ($/BOE):
Production and ad valorem taxes
$
4.10
$
4.88
General and administrative - cash component(4)
0.76
0.59
Total operating expense - cash
$
4.86
$
5.47
General and administrative - non-cash unit compensation expense
$
0.12
$
0.10
Interest expense, net
$
3.08
$
3.39
Depletion
$
9.85
$
9.65
(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.
Royalty Income
Our royalty income is a function of oil, natural gas, and natural gas liquids production volumes sold and average prices received for those volumes.
Royalty income decreased $32.0 million during the three months ended March 31, 2023 compared to the same period in 2022. Changes in average pricing during 2023 contributed to approximately $52.7 million of the total decrease due primarily to lower average oil prices, and to a lesser extent, natural gas and natural gas liquids prices received for our production in 2023. The decrease due to lower pricing was partially offset by $20.7 million in additional royalty income due to an 11% increase in production volumes during the three months ended March 31, 2023 compared to the same period in 2022. This production growth stems from new well additions between periods due to several acquisitions.
The following table presents production and ad valorem taxes for the three months ended March 31, 2023 and 2022:
Three Months Ended March 31,
2023
2022
Amount (In thousands)
Per BOE
Percentage of Royalty Income
Amount (In thousands)
Per BOE
Percentage of Royalty Income
Production taxes
$
8,177
$
2.60
5.1
%
$
9,870
$
3.47
5.1
%
Ad valorem taxes
4,710
1.50
2.9
4,000
1.41
2.1
Total production and ad valorem taxes
$
12,887
$
4.10
8.0
%
$
13,870
$
4.88
7.2
%
In general, production taxes are directly related to production revenues and are based upon current year commodity prices. Production taxes as a percentage of royalty income for the three months ended March 31, 2023 remained consistent with the same period in 2022. Ad valorem taxes are based, among other factors, on property values driven by prior year commodity prices. The increase in ad valorem taxes is primarily due to higher valuations assigned to our oil and natural gas interests period over period driven by higher average commodity prices in 2022.
Depletion
The $3.6 million increase in depletion expense for the three months ended March 31, 2023 compared to the same period in 2022 was due primarily to production growth between the periods. The average depletion rate also increased slightly to $9.85 for the three months ended March 31, 2023 compared to the rate of $9.65 for the same period in 2022 due primarily to higher value leasehold being transferred into the amortization base in the 2023 period.
Derivative Instruments
The following table shows the net gain (loss) on derivative instruments and the net cash receipts (payments) on derivatives for the periods presented:
Three Months Ended March 31,
2023
2022
(In thousands)
Gain (loss) on derivative instruments
$
(15,103)
$
(18,359)
Net cash receipts (payments) on derivatives(1)
$
(2,215)
$
(10,264)
(1)The three months ended March 31, 2022 includes cash paid on commodity contracts terminated prior to their contractual maturity of $4.2 million.
We recorded losses on our derivative instruments for the three months ended March 31, 2023 and 2022 primarily due to market prices being higher than the strike prices on our open derivative contracts. We are required to recognize all derivative instruments on our balance sheet as either assets or liabilities measured at fair value. See Note 10—Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our open contracts at March 31, 2023.
Provision for (Benefit from) Income Taxes
The $6.8 million increase in income tax expense for the three months ended March 31, 2023 compared to the same period in 2022 resulted primarily due to the increase in pre-tax income attributable to the Partnership as a result of the expiration of the special income allocation at December 31, 2022 and the impact of maintaining a valuation allowance against the Partnership’s deferred tax assets as of March 31, 2022. See Note 9—Income Taxes of the notes to the condensed consolidated financial statements included elsewhere in this report for further details.
Net Income (Loss) Attributable to Non-controlling Interest
The $57.1 million decrease in net income (loss) attributable to non-controlling interest for the three months ended March 31, 2023 compared to the same period in 2022 is primarily due to the expiration of the special income allocation at December 31, 2022.
As we pursue our business and financial strategy, we regularly consider which capital resources, including cash flow and equity and debt financings, are available to meet our future financial obligations and liquidity requirements. Our future ability to grow proved reserves will be highly dependent on the capital resources available to us. Our primary sources of liquidity have been cash flows from operations, proceeds from sales of non-core assets, equity and debt offerings and borrowings under the Operating Company’s credit agreement. Our primary uses of cash have been distributions to our unitholders, repayments of debt, capital expenditures for the acquisition of our mineral interests and royalty interests in oil and natural gas properties and repurchases of our common units. At March 31, 2023, we had approximately $239.1 million of liquidity consisting of $9.1 million in cash and cash equivalents and $230.0 million available under the Operating Company’s credit agreement.
Our working capital requirements are supported by our cash and cash equivalents and the Operating Company’s credit agreement. We may draw on the Operating Company’s credit agreement to meet short-term cash requirements, or issue debt or equity securities as part of our longer-term liquidity and capital management program. Because of the alternatives available to us as discussed above, we believe that our short-term and long-term liquidity are adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our acquisitions of mineral and royalty interests, distributions, debt service obligations and repayment of debt maturities, common unit and senior note repurchases and any amounts that may ultimately be paid in connection with contingencies.
Continued prolonged volatility in the capital, financial and/or credit markets due to the COVID-19 pandemic, the war in Ukraine, the depressed commodity markets and, or adverse macroeconomic conditions, including persistent inflation, rising interests rates, global supply chain disruptions and increasing concerns over a potential economic downturn or recession, may limit our access to, or increase our cost of, capital or make capital unavailable on terms acceptable to us or at all. Although we expect that our sources of funding will be adequate to fund our short-term and long-term liquidity requirements, we cannot assure you that the needed capital will be available on acceptable terms or at all.
Cash Flows
The following table presents our cash flows for the periods indicated:
Three Months Ended March 31,
2023
2022
(In thousands)
Cash Flow Data:
Net cash provided by (used in) operating activities
$
107,243
$
135,838
Net cash provided by (used in) investing activities
(116,583)
31,957
Net cash provided by (used in) financing activities
267
(174,177)
Net increase (decrease) in cash and cash equivalents
$
(9,073)
$
(6,382)
Operating Activities
Our operating cash flow is sensitive to many variables, the most significant of which are the volatility of prices for oil and natural gas and the volumes of oil and natural gas sold by our producers. The decrease in net cash provided by operating activities during the three months ended March 31, 2023 compared to the same period in 2022 was primarily driven by (i) lower royalty income and (ii) changes in our working capital accounts, due primarily to the timing of when collections are made on accounts receivable and payments are made on accounts payable and accrued liabilities, as well as an increase in taxes payable as our pre-tax income attributable to the Partnership increases. These cash outflows were partially offset by a decrease in cash paid for derivative settlements. See “—Results of Operations” for discussion of significant changes in our revenues and expenses.
Net cash used in investing activities during the three months ended March 31, 2023 primarily related to the acquisition of oil and natural gas interests in the Drop Down and from other third-party acquisitions.
Net provided by in investing activities during the three months ended March 31, 2022 primarily related to proceeds from the divestitures of oil and natural gas interests.
Financing Activities
Net cash provided by financing activities during the three months ended March 31, 2023 primarily resulted from $118.0 million of borrowings under the Operating Company’s revolving credit facility, which were offset by distributions of $84.7 million to our unitholders and $33.0 million of common unit repurchases.
Net cash used in financing activities during the three months ended March 31, 2022, was primarily related to distributions of $78.9 million to our unitholders and $39.3 million of common unit repurchases which included approximately $37.3 million for the repurchase of 1.5 million common units from a significant unitholder in a privately negotiated transaction. Additionally, we made net repayments of $56.0 million under the Operating Company’s revolving credit facility during the first quarter of 2022.
Capital Resources
The Operating Company’s Revolving Credit Facility
At March 31, 2023, the Operating Company’s credit agreement, which matures on June 2, 2025, had an elected commitment amount of $500.0 million, with $270.0 million in outstanding borrowings and $230.0 million of availability.
See Note 6—Debt of the notes to the condensed consolidated financial statements included elsewhere in this report for additional discussion of our outstanding debt at March 31, 2023.
Capital Requirements
Repurchases of Securities
Under our current common unit repurchase program, the board of directors of our General Partner has authorized us to acquire up to $750.0 million of our common units. As of March 31, 2023, $496.7 million remains available for use to repurchase units under this repurchase program, excluding excise tax.
We may also from time to time opportunistically repurchase some of the outstanding Notes in open market purchases or in privately negotiated transactions.
Cash Distributions
The distribution for the first quarter of 2023 is $0.33 per common unit payable on May 18, 2023 to common unitholders of record at the close of business on May 11, 2023. The dividend consists of a base quarterly dividend of $0.25 per common unit and a variable quarterly dividend of $0.08 per common unit. Future base and variable dividends are at the discretion of the board of directors of our General Partner.
See Note 7—Unitholders' Equity and Distributions of the notes to the condensed consolidated financial statements included elsewhere in this report for further discussion of the repurchase program and distributions.
Critical Accounting Estimates
There have been no changes to our critical accounting estimates from those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2022.
Recent Accounting Pronouncements
See Note 2—Summary of Significant Accounting Policies included in the condensed notes to the consolidated financial statements included elsewhere in this report for recent accounting pronouncements not yet adopted, if any.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to market risk, including the effects of adverse changes in commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses.
Commodity Price Risk
Our major market risk exposure is in the pricing applicable to the oil and natural gas production of our operators. Realized prices are driven primarily by the prevailing worldwide price for crude oil and prices for natural gas in the United States. Both crude oil and natural gas realized prices are also impacted by the quality of the product, supply and demand balances in local physical markets and the availability of transportation to demand centers. Pricing for oil and natural gas production has been historically volatile and unpredictable and the prices that our operators receive for production depend on many factors outside of our or their control, such as the war in Ukraine, rising interest rates, global supply chain disruptions, a potential economic downturn or recession, the COVID-19 pandemic and actions taken by OPEC members and other exporting nations. We cannot predict events that may lead to future price volatility and the near term energy outlook remains subject to heightened levels of uncertainty.
We historically have used fixed price swap contracts, fixed price basis swap contracts and costless collars with corresponding put and call options to reduce price volatility associated with certain of our royalty income as discussed in Note 10—Derivatives of the notes to the condensed consolidated financial statements included elsewhere in this report.
At March 31, 2023, we had a net liability derivative position related to our commodity price derivatives of $3.1 million. Utilizing actual derivative contractual volumes under our contracts as of March 31, 2023, a 10% increase in forward curves associated with the underlying commodity would have decreased the net liability position by $0.6 million to $2.5 million, while a 10% decrease in forward curves associated with the underlying commodity would have increased the net liability derivative position by $0.5 million to $3.7 million. However, any cash derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument.
Credit Risk
We are subject to risk resulting from the concentration of royalty income in producing oil and natural gas interests and receivables with a limited number of significant purchasers and producers. We do not require collateral and the failure or inability of our significant purchasers to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency or liquidation may adversely affect our financial results. Volatility in commodity pricing environment and macroeconomic conditions may enhance our purchaser credit risk.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under the Operating Company’s credit agreement. The terms of the credit agreement provide for interest on borrowings at a floating rate equal to (i) term SOFR plus 0.10% (“Adjusted Term SOFR”) or (ii) an alternate base rate (which is equal to the greatest of the prime rate, the Federal Funds effective rate plus 0.50%, and 1-month Adjusted Term SOFR plus 1.00%), in each case plus the applicable margin. The applicable margin ranges from 1.00% to 2.00% per annum in the case of the alternative base rate and from 2.00% to 3.00% per annum in the case of Adjusted Term SOFR, in each case depending on the amount of the loans outstanding in relation to the commitment, which is calculated using the least of the maximum credit amount, the aggregate elected commitment amount and the borrowing base. We are obligated to pay a quarterly commitment fee ranging from 0.375% to 0.500% per year on the unused portion of the commitment. As of March 31, 2023, we had $270.0 million in outstanding borrowings. During the three months ended March 31, 2023, the weighted average interest rate on the Operating Company’s revolving credit facility was 6.10%.
Evaluation of Disclosure Control and Procedures. Under the direction of the Chief Executive Officer and Chief Financial Officer of our General Partner, we have established disclosure controls and procedures, as defined in Rule 13a-15(e) and 15d-15(e) under the Exchange Act, that are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. The disclosure controls and procedures are also intended to ensure that such information is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.
As of March 31, 2023, an evaluation was performed under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Exchange Act. Based upon the evaluation, the Chief Executive Officer and Chief Financial Officer of our General Partner have concluded that as of March 31, 2023, our disclosure controls and procedures are effective.
Changes in Internal Control over Financial Reporting. There have not been any changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2023 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.
Due to the nature of our business, we are, from time to time, involved in routine litigation or subject to disputes or claims related to our business activities. In the opinion of our management, none of the pending litigation, disputes or claims against us, if decided adversely, will have a material adverse effect on our financial condition, cash flows or results of operations. See Note 12—Commitments and Contingencies of the notes to the condensed consolidated financial statements included elsewhere in this report.
ITEM 1A. RISK FACTORS
Our business faces many risks. Any of the risks discussed in this report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also materially impair our business operations, financial condition or future results.
As of the date of this filing, we continue to be subject to the risk factors previously disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the SEC on February 23, 2023 and in subsequent filings we make with the SEC. There have been no material changes in our risk factors from those described in our Annual Report on Form 10-K for the year ended December 31, 2022.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Unregistered Sales of Equity Securities
None.
Issuer Repurchases of Equity Securities
Our common unit repurchase activity for the three months ended March 31, 2023 was as follows:
Period
Total Number of Units Purchased
Average Price Paid Per Unit(1)(3)
Total Number of Units Purchased as Part of Publicly Announced Plan
Approximate Dollar Value of Units that May Yet Be Purchased Under the Plan(2)(3)
(In thousands, except unit amounts)
January 1, 2023 - January 31, 2023
357,868
$
31.52
357,868
$
518,099
February 1, 2023 - February 28, 2023
198,662
$
30.96
198,662
$
511,948
March 1, 2023 - March 31, 2023
558,400
$
27.33
558,400
$
496,685
Total
1,114,930
$
29.33
1,114,930
(1)The average price paid per common unit includes any commissions paid to repurchase a common unit.
(2)On July 26, 2022, the board of directors of our General Partner increased the authorization under our then-in-effect common unit repurchase program from $250.0 million to $750.0 million, excluding excise tax. This repurchase program has no expiration date and remains subject to market conditions, applicable legal requirements, contractual obligations and other factors and may be suspended from time to time, modified, extended or discontinued by the board of directors of our General Partner at any time.
(3)The Inflation Reduction Act of 2022, which was enacted into law on August 16, 2022, imposed a nondeductible 1% excise tax on the net value of certain stock repurchases made after December 31, 2022. All dollar amounts presented exclude such excise taxes, as applicable.
The following financial information from the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2023, formatted in Inline XBRL: (i) Condensed Consolidated Balance Sheets, (ii) Condensed Consolidated Statements of Operations, (iii) Condensed Consolidated Statement of Changes in Unitholders’ Equity, (iv) Condensed Consolidated Statements of Cash Flows and (v) Condensed Notes to Consolidated Financial Statements.
104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
*
Filed herewith.
**
The certifications attached as Exhibit 32.1 accompany this Quarterly Report on Form 10-Q pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, and shall not be deemed “filed” by the Registrant for purposes of Section 18 of the Securities Exchange Act of 1934, as amended.
Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
