What changed in this filing

/stocks — the workspaceLOADING

Item 7. Management’s Discussion and Analysis

2022-02-24 compared with 2021-02-25 · 82 added, 52 removed, 113 unchanged (54% of the section changed)

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

This discussion, which presents our results of operations for the fiscal years ended December 31, 2021, and December 31, 2020, should be read in conjunction with our Consolidated Financial Statements and the accompanying notes.

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.

2021 Overview

Our results during 2020 were affected by industrywide volatility in terms of COVID-19 pandemic driven demand reductions and price challenges resulting in operator curtailments and decreased activity levels.

Our results during 2021 to a large extent benefitted from industrywide increases in realized oil and natural gas sales prices and increases in Royalty Properties sales volumes from continued drilling activity in the Permian Basin, offset partially by decreases in drilling activity and NPI oil sales volumes in the Bakken and a decrease in NPI natural gas sales due to the divestiture of the Hugoton NPI in 2020.

Significant results include the following:

1 unchanged sentence

Distributions of $53.9 million to our limited partners;

Divestiture of our Hugoton net profits interest located in Texas County, Oklahoma and Stevens County, Kansas, to a third party for $5.0 million in proceeds, net of transaction costs and customary holdbacks.

This included operated working interests and related properties, our field office and our gathering system and related assets;

First payments on 414 gross and three net new wells completed on our Royalty Properties and 90 gross and two net new wells completed on our NPI Properties.

The wells were located in 60 counties and parishes in seven states with the majority of the activity concentrated in the Permian Basin and Bakken.

Acquisition of 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;

Acquisition of 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;

First payments on 725 gross and four net new wells completed on our Royalty Properties and 45 gross and less than one net new well completed on our NPI Properties.

The wells were located in 51 counties and parishes in eight states with the majority of the activity concentrated in the Permian Basin and Bakken.

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 $0.3 million includes consummation of 14 leases and pooling elections of our mineral interest in undeveloped properties located in nine counties in two states.

Critical Accounting Policies

Total lease bonus of $0.8 million includes consummation of 16 leases and pooling elections of our mineral interest in undeveloped properties located in eight counties in four states.

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 units-of-production method.

These capitalized costs are subject to a ceiling test that 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.

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.

2 unchanged sentences

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.

See “Item 8.

Financial Statements and Supplementary Data”.

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 extremely limited involvement and 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.

Results of Operations

13 unchanged sentences

Comparison of the years ended December 31, 2021 and 2020

The decrease in oil sales volumes attributable to our Royalty Properties during 2020 is primarily a result of decreased Permian Basin production due to lower suspense releases on new wells, operator curtailments based on the low commodity price environment, and natural declines, partially offset by higher suspense releases on new wells in the Bakken region and Rockies.

The decrease in natural gas sales volumes attributable to our Royalty Properties during 2020 is primarily a result of first and second quarter decreases in production across multiple regions due to operator curtailments based on the low commodity price environment and higher natural declines when compared to the prior year, partially offset by higher suspense releases on new wells in the Bakken, Rockies, and Southeast regions.

Oil sales volumes attributable to our NPI properties remained consistent during 2019 and 2020.

The lack of change is primarily a result of higher suspense releases on new wells in the Bakken region and increased production in the Permian Basin, offset by second quarter 2020 Bakken region curtailments due to the low commodity price environment.

The decrease in natural gas sales volumes attributable to our NPI properties during 2020 is primarily a result of lower Hugoton Field production contribution due to the September 1, 2020 effective date of the NPI divestiture, declining Fayetteville Shale production, and lower suspense releases on new wells in the Permian Basin compared to 2019, partially offset by increased production in the Permian Basin and Bakken region.

Lease bonus revenue decreased 92% from $3.8 million in 2019 to $0.3 million in 2020.

The decrease is primarily a result of higher prior year leasing activity in the Permian Basin when compared to 2020 leasing activity.

Other revenue increased 80% from $0.5 million in 2019 to $0.9 million in 2020.

The increase is primarily a result of higher current year favorable normal course of business legal settlements on our Royalty Properties.

Production taxes and operating expenses decreased 14% from $6.6 million in 2019 to $5.7 million in 2020.

The decrease is primarily a result of lower production taxes due to lower oil and natural gas sales volumes and lower oil and natural gas prices, partially offset by higher oil and natural gas transportation costs in the Permian Basin and Bakken region.

Depreciation, depletion and amortization decreased 11% from $13.3 million in 2019 to $11.9 million in 2020.

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 23% from $6.1 million in 2019 to $7.5 million in 2020.

The increase is primarily a result of higher non-recurring land information technology project costs of $0.6 million, higher public company compliance costs, and non-recurring Hugoton and Huffman NPI divestiture transaction and severance costs of $1.0 million, partially offset by lower employee bonus expense.

Net cash provided by operating activities decreased 40% from $66.1 million in 2019 to $39.4 million in 2020.

The decrease is primarily a result of lower operating revenues largely driven by lower oil and natural gas sales volumes and realized prices for Royalty properties, lower natural gas sales volumes and oil and natural gas realized prices for NPI properties, and lower lease bonus revenue in 2020 when compared to 2019.

Huffman Acquisition

On March 29, 2019, the Partnership acquired producing and nonproducing mineral, royalty and net profits interests pursuant to a Contribution and Exchange Agreement (the "Contribution and Exchange Agreement") with H.

Huffman & Co., A Limited Partnership, an Oklahoma limited partnership (“HHC”), The Buffalo Co., A Limited Partnership, an Oklahoma limited partnership (“TBC”

and, together with HHC, the “Acquired Entities”), Huffman Oil Co., L.L.C., an Oklahoma limited liability company, and the equity holders of the Acquired Entities (the “Huffman Acquisition").

The mineral and royalty properties acquired pursuant to the Contribution and Exchange Agreement consisted of varying undivided interests totaling approximately 76,000 net acres located in 169 counties in 14 states, including positions in the Bakken region of North Dakota and interests in multiple enhanced oil recovery units in the Permian Basin.

In addition to conveying mineral, royalty and net profits interests to the Partnership, the Acquired Entities delivered funds to the Partnership in an amount equal to their cash receipts during the period from January 1, 2019 through March 29, 2019 of $1.4 million (including adjustments made post-closing).

The contributing entities conveyed their interests to the Partnership and affiliates of its General Partner in exchange for 2,400,000 common limited partnership units.

On October 21, 2020, the Partnership and affiliates of its General Partner closed the divestiture of our immaterial HHC entity, including all associated working interest properties and net profits interest.

The increase in oil sales volumes attributable to our Royalty Properties during 2021 is primarily a result of higher suspense releases on new wells in the Permian Basin and Bakken region, partially offset by lower suspense releases on new wells in the Rockies and natural production declines in the Permian Basin, Bakken region, and Mid-Continent.

The increase in natural gas sales volumes attributable to our Royalty Properties during 2021 is primarily a result of higher suspense releases on new wells in the Permian Basin and Mid-Continent and increased production in the Bakken region and Barnett Shale, partially largely offset by lower suspense releases on new wells in the Rockies, natural production declines in the Mid-Continent, and decreased production in other areas of Texas and the Southeast region.

The decrease in oil sales volumes attributable to our NPI properties during 2021 is primarily a result of lower suspense releases for new wells in the Bakken region and Permian Basin and natural production declines across all regions.

The decrease in natural gas sales volumes attributable to our NPI properties during 2021 is primarily the result of the absence of 2021 production from the Hugoton Field due to the Hugoton NPI divestiture in the third quarter of 2020 and decreased production in Mid-Continent, partially offset by increased production in the Bakken region and increased Fayetteville Shale production due to higher prior period adjustments in the second quarter of 2021.

Production taxes and operating expenses increased 33% from 2020 to 2021.

The increase is primarily a result of higher production taxes attributable to higher oil and natural gas sales prices, partially offset by lower ad valorem taxes.

Depreciation, depletion and amortization decreased 12% from 2020 to 2021.

We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including acquisitions and divestitures.

General and administrative expenses decreased 31% from 2020 to 2021.

The decrease is primarily a result of lower compensation expenses due to the forgiveness of the Operating Partnership’s $0.9 million and $0.8 million Paycheck Protection Program loans in the second and third quarter of 2021, respectively, which were applied as non-recurring credits of compensation costs previously reimbursed between the Partnership and the Operating Partnership.

The remainder of the decrease is attributable to non-recurring Hugoton and Huffman NPI divestiture transaction and severance costs of $1.0 million in 2020 and lower information technology project costs.

These decreases were partially offset by higher compensation expenses due to the reduction of overhead billed to two NPIs which were divested in 2020.

Net cash provided by operating activities increased 78% from 2020 to 2021.

The increase is primarily a result of higher Royalties revenue receipts, net of production taxes and operating expenses paid and lower compensation expenses paid due to the forgiveness of the Operating Partnership’s $0.9 million and $0.8 million Paycheck Protection Program loans in the second and third quarter of 2021, respectively, which were applied as non-recurring credits of compensation costs previously reimbursed between the Partnership and the Operating Partnership.

Acquisition for Units

On December 31, 2021, pursuant to a non-taxable contribution and exchange agreement with Gemini 5 Thirty, LP, a Texas limited partnership (“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 complimentary to our business.

The transaction was accounted for as an acquisition of assets under U.S.

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.

At closing, in addition to conveying mineral and royalty interests to the Partnership, Gemini delivered funds to the Partnership in an amount equal to their cash receipts during the period from October 1, 2021 through December 31, 2021 of $1.9 million.

The contributed cash, 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.

On June 30, 2021, pursuant to a contribution and exchange agreement with JSFM, LLC, a Wyoming limited liability company (“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 complimentary to our business.

The transaction was accounted for as an acquisition of assets under U.S.

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.

At closing, in addition to conveying overriding royalty interests to the Partnership, JSFM delivered funds to the Partnership in an amount equal to their cash receipts during the period from April 1, 2021 through June 30, 2021 of $0.4 million.

The contributed cash and final settlement net cash receipts, net of capitalized transaction costs paid, of $0.7 million are included in the net cash contributed in acquisition on the consolidated statement of cash flows for the year ended December 31, 2021.

Net Profits Interest Divestiture

2 unchanged sentences

Transaction costs of $0.5 million are included in general and administrative expenses on the consolidated income statement for the year ended December 31, 2020.

Holdbacks of $0.2 million are included in trade and other receivables on the consolidated balance sheet as of December 31, 2020.

Final net proceeds from the sale are subject to customary holdbacks and post-closing adjustments.

Texas Margin Tax

9 unchanged sentences

Capital Resources

Our primary sources of capital are our cash flows from the NPI and the Royalty Properties.

Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from NPIs and the Royalty Properties (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.

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.

2 unchanged sentences

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.

3 unchanged sentences

(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 ongoing COVID-19 pandemic and continued oil and natural gas market 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 ongoing COVID-19 pandemic, which are beyond our control.

If market conditions were to change due to further declines in oil prices or uncertainty created by the ongoing COVID-19 pandemic, and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. 

We continue to evaluate potential reductions in all discretionary spending.

The current economic environment is volatile, and therefore, we cannot predict the ultimate impact on our liquidity or cash flows.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that are material to unitholders.

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 continued oil and natural gas market volatility.

Although demand and market prices for oil and natural gas have recently increased due to the rising energy demand, 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, 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 on our liquidity or cash flows.

Liquidity and Working Capital

9 unchanged sentences

Total distributions paid in 2021

February 1, 2021

January 31, 2022

February 10, 2022

8 unchanged sentences

Net proceeds realized by the Operating Partnership during September through November 2021 were reflected in NPI payments made during October through December 2021.

These payments were included in the fourth quarter distribution paid in early 2021 and are excluded from this 2020 analysis.

These payments were included in the fourth quarter distribution paid February 10, 2022 and are excluded from this 2021 analysis.

Royalty Properties

1 unchanged sentence

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 above described costs including cash reserves, our net cash receipts from the Royalty Properties during October 2019 through September 2020 were $30.0 million, of which $28.8 million (96%) was distributed to the limited partners and $1.2 million (4%) was distributed to the General Partner.

After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2020 through September 2021 were $44.8 million, of which $43.0 million (96%) was distributed to the limited partners and $1.8 million (4%) was distributed to the General Partner.

Proceeds received by us from the Royalty Properties during October through December 2021 became part of the fourth quarter distribution paid in early 2022, which is excluded from this 2021 analysis.

23 unchanged sentences

Cash receipts attributable to the Partnership's Royalty Properties during the 2021 fourth quarter totaled $21.2 million.

These receipts generally reflect oil sales during September through November 2020 and natural gas sales during August through October 2020.

Approximately 82% of these receipts reflect oil sales during September 2021 through November 2021 and natural gas sales during August 2021 through October 2021, and approximately 18% from prior sales periods.

The average indicated prices for oil and natural gas sales during the 2021 fourth quarter attributable to the Royalty Properties were $68.46/bbl and $4.15/mcf, respectively.

Cash receipts attributable to the Partnership's NPI during the 2021 fourth quarter totaled $4.2 million.

These receipts generally reflect oil and natural gas sales from the properties underlying the NPI during August through October 2020.

Approximately 77% of these receipts reflect oil sales and natural gas sales during August 2021 through October 2021, and approximately 23% from prior sales periods.

The average indicated prices for oil and natural gas sales during the 2021 fourth quarter attributable to the NPI were $68.11/bbl and $4.20/mcf, respectively.

10 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis