Item 7. Management’s Discussion and Analysis
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
Objective
 
The following discussion summarizes our results of operations and liquidity and capital resources for the fiscal years ended December 31, 2022 and 2021 and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report. A discussion of results of operations and liquidity and capital resources for fiscal year 2020 has been omitted from this report but may be found at “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2021, filed with the SEC on February 24, 2022, and is incorporated by reference in this report from such prior Annual Report on Form 10-K. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements from period to period, and the primary factors that accounted for those changes.
 
2022 Overview
 
Our results during 2022, to a large extent, benefitted from industrywide increases in realized oil and natural gas sales prices. Increases in Royalty Properties and NPI sales volumes were largely a result of continued drilling activity in the Permian Basin. Significant results include the following:
 
 
●
Net income of $130.6 million;
 
 
●
Distributions of $131.9 million to our limited partners;
 
 
●
Acquisition of mineral, royalty and overriding royalty interests representing approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for 816,719 common units representing limited partnership interests in the Partnership valued at $20.4 million and issued pursuant to the Partnership's registration statement on Form S-4;
 
 
●
Acquisition of mineral and royalty interests representing approximately 3,600 net royalty acres located in 13 counties across Colorado, Louisiana, Ohio, Oklahoma, Pennsylvania, West Virginia and Wyoming in exchange for 570,000 common units representing limited partnership interests in the Partnership valued at $14.8 million and issued pursuant to the Partnership's registration statement on Form S-4;
 
 
●
First payments on 1,808 gross and ten net new wells completed on our Royalty Properties and 112 gross and two net new wells completed on our NPI Properties. The wells were located in 63 counties and parishes in 12 states with the majority of the activity concentrated in the Permian Basin, Rockies, and South Texas. Included in these totals are wells in which we own both a royalty interest and a net profits interest. Wells with such overlapping interests are counted in both categories;
 
 
●
Total lease bonus of $8.7 million includes consummation of 31 leases and pooling elections of our mineral interest in undeveloped properties located in 17 counties in four states. Of the total, $7.3 million was attributable to a record lease bonus executed in Reagan County, Texas.
 
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Critical Accounting Estimates
 
The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United State (“U.S. GAAP”), which requires us to make certain estimates and apply judgments that affect our financial position and results of operations as reflected in our financial statements. Actual results may differ from those estimates. The Partnership’s accounting policies are summarized in Note 1 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.
 
Management continually reviews our accounting policies, how they are applied, and how they are reported and disclosed in our financial statements. The following items require significant estimation or judgment:
 
Oil and Natural Gas Properties
 
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. These capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties.
 
The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that more significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.
 
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.
 
Revenue Recognition
 
The pricing of oil and natural gas sales from the Royalty Properties and NPI is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we have no operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI.
 
Revenues from Royalty Properties and NPI are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to four months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices. Estimates of uncollected revenues and unpaid expenses from Royalty Properties (which are interests in oil and natural gas leases that give the Partnership the right to receive a portion of the production from the leased acreage, without bearing the costs of such production) and net profits overriding royalty interests (referred to as the Net Profits Interest, or “NPI”) operated by nonaffiliated entities are particularly subjective due to our inability to gain accurate and timely information. Identified differences between our accrued revenue estimates and actual revenue received historically have not been significant.
 
The Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations. The Partnership’s right to revenues from Royalty Properties and NPI occurs at the time of production, at which point, payment is unconditional, and no remaining performance obligation exists for the Partnership. Accordingly, the Partnership’s revenue contracts for Royalty Properties and NPI do not generate contract assets or liabilities.
 
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Results of Operations
 
Normally, our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and average sales prices are shown in the following table.
 
 
 
Years Ended December 31,
 
 
 
 
 
Accrual basis sales volumes:
 
2022
 
 
2021
 
 
Change %
 
Royalty Properties natural gas sales (mmcf)
 
 
4,416
 
 
 
3,665
 
 
 
21
%
Royalty Properties oil sales (mbbls)
 
 
1,328
 
 
 
1,007
 
 
 
32
%
NPI natural gas sales (mmcf)
 
 
1,458
 
 
 
1,344
 
 
 
9
%
NPI oil sales (mbbls)
 
 
498
 
 
 
380
 
 
 
31
%
 
 
 
 
 
 
 
 
 
 
 
 
 
Accrual basis average sales price:
 
 
 
 
 
 
 
 
 
 
 
 
Royalty Properties natural gas sales ($/mcf)
 
$
5.61
 
 
$
3.63
 
 
 
54
%
Royalty Properties oil sales ($/bbl)
 
$
81.70
 
 
$
60.26
 
 
 
36
%
NPI natural gas sales ($/mcf)
 
$
5.92
 
 
$
4.14
 
 
 
43
%
NPI oil sales ($/bbl)
 
$
80.02
 
 
$
60.68
 
 
 
32
%
 
Comparison of the years ended December 31, 2022 and 2021
 
The increase in oil sales volumes attributable to our Royalty Properties during 2022 is primarily a result of higher suspense releases on new wells in the Permian Basin and South Texas, higher suspense releases on new wells and increased production from acquired wells in the Rockies, and increased production in the Bakken region. The increase in natural gas sales volumes attributable to our Royalty Properties during 2022 is primarily a result of higher suspense releases on new wells in the Permian Basin, South Texas, and the Southeast and higher suspense releases on new wells and increased production from acquired wells in the Rockies, partially offset by natural production declines in the Barnett Shale.
 
The increase in oil sales volumes attributable to our NPI properties during 2022 is primarily a result of increased production and higher suspense releases on new wells in the Permian Basis and higher suspense releases on new wells in the Bakken region, partially offset by natural production declines in the Bakken region. The increase in natural gas sales volumes attributable to our NPI properties during 2022 is primarily a result of the increased production and higher suspense releases on new wells in the Permian Basin, partially offset by natural production declines in the Bakken region and decreased Fayetteville Shale production due to higher prior period adjustments.
 
The increase in lease bonus revenue from 2021 to 2022 is primarily attributable to receipt of approximately $7.3 million from a lease executed on September 30, 2022, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $30,000 per acre and a 25% royalty.
 
Production taxes and operating expenses increased 70% from 2021 to 2022. The increase is primarily a result of higher proportionate production taxes due to higher oil and natural gas sales volumes and sales prices and higher ad valorem taxes.
 
Depreciation, depletion and amortization increased 82% from 2021 to 2022. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including acquisitions.
 
General and administrative expenses increased 58% from 2021 to 2022. The increase is primarily attributable to higher compensation expenses due to market adjustments and forgiveness of the Operating Partnership’s $0.9 million and $0.8 million Paycheck Protection Program loans in the second and third quarters of 2021, respectively, which were applied as non-recurring credits of compensation costs previously reimbursed between the Partnership and the Operating Partnership partially offset by lower 2022 information technology project costs.
 
Net cash provided by operating activities increased 109% from 2021 to 2022. The increase is primarily a result of higher Royalties revenue receipts, net of production taxes and operating expenses, higher NPI payment receipts, and higher lease bonus receipts, partially offset by higher general and administrative expenses and ad valorem taxes paid.
 
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Acquisitions for Units
 
On September 30, 2022, pursuant to a non-taxable contribution and exchange agreement with Excess, the Partnership acquired mineral, royalty and overriding royalty interests totaling approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for 816,719 common units representing limited partnership interests in the Partnership valued at $20.4 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing, net of capitalized transaction costs paid, of $0.9 million are included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2022.
 
On March 31, 2022, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests representing approximately 3,600 net royalty acres located in 13 counties across Colorado, Louisiana, Ohio, Oklahoma, Pennsylvania, West Virginia and Wyoming in exchange for 570,000 common units representing limited partnership interests in the Partnership valued at $14.8 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.8 million are included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2022.
 
On December 31, 2021, pursuant to a non-taxable contribution and exchange agreement with Gemini, the Partnership acquired mineral and royalty interests representing approximately 4,600 net royalty acres located in 27 counties across New Mexico, Oklahoma, Texas and Wyoming in exchange for 1,580,000 common units representing limited partnership interests in the Partnership valued at $31.3 million and issued pursuant to the Partnership's registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing, net of capitalized transaction costs paid, of $1.6 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2021. Final settlement net cash received, net of capitalized transaction costs, of $0.4 million is included in the net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2022.
 
On June 30, 2021, pursuant to a non-taxable contribution and exchange agreement with JSFM, the Partnership acquired overriding royalty interests in the Bakken Trend totaling approximately 6,400 net royalty acres located in Dunn, McKenzie, McLean and Mountrail Counties, North Dakota in exchange for 725,000 common units representing limited partnership interests in the Partnership valued at $12.2 million and issued pursuant to the Partnership’s registration statement on Form S-4. We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.7 million are included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2021.
 
Texas Margin Tax
 
Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, joint ventures and certain other business entities having limited liability protection.
 
Limited partnerships that receive at least 90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code provides such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.
 
Each unitholder is urged to consult an independent tax advisor regarding the requirements for filing state income, franchise and Texas margin tax returns.
 
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Liquidity and Capital Resources
 
Capital Resources
 
Our primary sources of capital, on both a short-term and long-term basis, are our cash flows from the Royalty Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and NPIs (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves. Additional cash requirements include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See below for the dates of cash distributions to unitholders.
 
Contractual Obligations
 
The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The third amendment to our Office Lease was executed in April 2017 for a term of 129 months, beginning June 1, 2018 and expiring in 2029. Under the third amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations are summarized in Note 7 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.
 
We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt.
 
Pursuant to the terms of the partnership agreement, we cannot incur indebtedness, other than trade payables, (i) in excess of $50,000 in the aggregate at any given time or (ii) which would constitute “acquisition indebtedness” (as defined in Section 514 of the Internal Revenue Code of 1986, as amended).
 
We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations despite potential material uncertainties that may impact us as a result of the spread of COVID-19 and any ongoing variants and increased oil and natural gas market volatility caused by the Russian invasion of Ukraine and the recent rise in inflation and interest rates. Although demand and market prices for oil and natural gas have remained strong due to the rising energy use and worldwide shortage of oil due to sanctions implemented on Russia, we cannot predict events that may lead to future price volatility. Our ability to fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas market and other financial and business factors, including the evolution of COVID-19 and any ongoing variants, along with the military conflict between Russia and Ukraine which are beyond our control. If market conditions were to change due to declines in oil prices or uncertainty created by COVID-19 or any ongoing variants and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. Despite recent improvements, the current economic environment is volatile, and therefore, we cannot predict the ultimate impact that COVID-19 or the ongoing military conflict between Russia and Ukraine will have on our liquidity or cash flows.
 
Liquidity and Working Capital
 
Cash and cash equivalents were $40.8 million as of December 31, 2022 and $28.3 million as of December 31, 2021.
 
Distributions
 
Distributions to limited partners and the General Partner related to cash receipts were as follows:
 
 
 
 
 
 
 
 
 
 
 
 
 
In Thousands
 
Year
 
Quarter
 
Record Date
 
Payment Date
 
Per Unit
Amount
 
 
Limited
Partners
 
 
General
Partner
 
2021
 
4th
 
January 31, 2022
 
February 10, 2022
 
$
0.639287
 
 
$
23,644
 
 
$
855
 
2022
 
1st
 
May 2, 2022
 
May 12, 2022
 
$
0.753926
 
 
 
28,313
 
 
 
965
 
2022
 
2nd
 
August 1, 2022
 
August 11, 2022
 
$
0.969012
 
 
 
36,391
 
 
 
1,357
 
2022
 
3rd
 
October 31, 2022
 
November 10, 2022
 
$
1.135019
 
 
 
43,553
 
 
 
1,615
 
 
 
Total distributions paid in 2022
 
 
 
 
 
$
131,901
 
 
$
4,792
 
2022
 
4th
 
January 30, 2023
 
February 9, 2023
 
$
0.884339
 
 
$
33,933
 
 
$
1,117
 
 
In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.
 
Net Profits Interests
 
We receive monthly payments from the Operating Partnership equal to 96.97% of the net proceeds actually realized by the Operating Partnership from the properties underlying the Net Profits Interest (or “NPI”). The Operating Partnership retains the 3.03% balance of these net proceeds. Net proceeds generally reflect gross proceeds attributable to oil and natural gas production actually received during the month, less production costs actually paid during the same month, net of budgeted capital expenditures. Production costs generally reflect drilling, completion, operating and general and administrative costs and exclude depletion, amortization and other non-cash costs. The Operating Partnership made NPI payments to us totaling $22.5 million during October 2021 through September 2022, which payments reflected 96.97% of total net proceeds of $23.2 million realized from September 2021 through August 2022. Net proceeds realized by the Operating Partnership during September through November 2022 were reflected in NPI payments made during October through December 2022. These payments were included in the fourth quarter distribution paid February 9, 2023 and are excluded from this 2022 analysis.
 
Royalty Properties
 
Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs because royalties and lease bonuses generally do not otherwise bear operating or similar costs. After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2021 through September 2022 were $114.2 million, of which $109.6 million (96%) was distributed to the limited partners and $4.6 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 2022 became part of the fourth quarter distribution paid in early 2023, which is excluded from this 2022 analysis.
 
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Distribution Determinations
 
The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement. The following calculation covering the period October 2021 through September 2022 demonstrates the method:
 
 
 
In Thousands
 
 
 
Limited
Partners
 
 
General
Partner
 
4% of net cash receipts from Royalty Properties
 
$
-
 
 
$
4,567
 
96% of net cash receipts from Royalty Properties
 
 
109,617
 
 
 
-
 
1% of NPI payments to our Partnership
 
 
-
 
 
 
225
 
99% of NPI payments to our Partnership
 
 
22,284
 
 
 
-
 
Total distributions
 
$
131,901
 
 
$
4,792
 
Operating Partnership share (3.03% of net proceeds)
 
 
 
 
 
 
703
 
Total General Partner share
 
 
 
 
 
$
5,495
 
% of total
 
 
96
%
 
 
4
%
 
In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our activities and those of the Operating Partnership during this period. Due to these fixed percentages, our General Partner does not have any incentive distribution rights or other right or arrangement that will increase its percentage share of net cash generated by our activities or those of the Operating Partnership.
 
During the period October 2021 through September 2022, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash. Available cash is defined as all cash and cash equivalents on hand at the end of that quarter (other than cash proceeds received by the Partnership from public or private offering of securities of the Partnership), less any amount of cash reserves that our General Partner determines is necessary or appropriate to provide for the conduct of its business or to comply with applicable laws or agreements or obligations to which we may be subject. Our practice is to accrue funds quarterly for amounts incurred throughout the year but invoiced and paid annually or semi-annually (e.g. ad valorem taxes and professional services). These amounts generally are not held for periods over one year.
 
Fourth Quarter 2022 Distribution Indicated Price
 
In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This “indicated price” does not necessarily reflect the contractual terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between the Partnership's cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments.
 
Cash receipts attributable to the Partnership's Royalty Properties during the 2022 fourth quarter totaled $29.0 million. Approximately 79% of these receipts reflect oil sales during September 2022 through November 2022 and natural gas sales during August 2022 through October 2022, and approximately 21% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 2022 fourth quarter were $76.32/bbl and $6.50/mcf, respectively.
 
Cash receipts attributable to the Partnership's NPI during the 2022 fourth quarter totaled $9.5 million. Approximately 52% of these receipts reflect oil sales and natural gas sales during August 2022 through October 2022, and approximately 48% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $78.76/bbl and $6.63/mcf, respectively.
 
General and Administrative Costs
 
In accordance with our partnership agreement, we bear all general and administrative and other overhead expenses subject to certain limitations. We reimburse our General Partner for certain allocable costs, including rent, wages, salaries and employee benefit plans. This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. Through December 31, 2022, the reimbursement amounts actually paid or accrued were less than the limitation.
 
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