The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements.
The accompanying notes are an integral part of these condensed consolidated financial statements
The accompanying notes are an integral part of these condensed consolidated financial statements
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 Basis of Presentation: Dorchester Minerals, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership that was formed in December 2001, and commenced operations on January 31, 2003. The unaudited condensed consolidated financial statements include the accounts of the Partnership and its wholly-owned subsidiaries Dorchester Minerals Oklahoma LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, Dorchester-Maecenas GP LLC, The Buffalo Co., A Limited Partnership, and DMLPTBC GP LLC.
The accompanying unaudited condensed consolidated financial statements of the Partnership have been prepared in accordance with generally accepted accounting principles in the United States ("U.S. GAAP") and pursuant to the rules and regulations of the U.S. Securities and Exchange Commission (“SEC”). The unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal and recurring adjustments unless indicated otherwise) that are, in the opinion of management, necessary for the fair presentation of our financial position and operating results for the interim period. Interim period results are not necessarily indicative of the results for the calendar year. For more information regarding limitations on the forward-looking statements contained herein, see page 1 of this quarterly report on Form 10-Q. Per-unit information is calculated by dividing the income or loss applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, consequently, basic and diluted income per unit do not differ. The accompanying unaudited condensed consolidated financial statements and related notes should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s 2018 Annual Report on Form 10-K.
The accompanying unaudited condensed consolidated financial statements include the consolidated results of the Partnership. All significant intercompany balances and transactions have been eliminated in consolidation.
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. For example, 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 Interests, or “NPIs”) operated by non-affiliated entities are particularly subjective due to our inability to gain accurate and timely information. Therefore, actual results could differ from those estimates.
Revenue Recognition – Revenues from Royalty properties and NPIs 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.
Revenues from lease bonus payments are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Partnership upon receipt of payment. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies, and includes proceeds from assignments of leasehold interests where the Partnership retains an interest. A lease agreement represents the Partnership’s contract with a lessee and generally transfers the rights to develop oil or natural gas, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period.
The Partnership does not record revenue for unsatisfied or partially unsatisfied performance obligations.
2 Acquisition for Units: On March 29, 2019, pursuant to a 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 Partnership acquired (i) a 96.97% net profits interest in certain working interests in various oil and gas properties owned by HHC, (ii) all of the minerals and royalty interests held by HHC, and (iii) all of the minerals and royalty interests held by TBC in exchange for 2,400,000 common units representing limited partnership interests in the Partnership (“Common Units”) valued at $43.8 million and issued pursuant to the Partnership's acquisition shelf registration statements on Form S-4. The Acquired Entities were 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. The unaudited condensed consolidated balance sheet as of September 30, 2019 includes $42.9 million in net property additions. Net property additions includes $4.3 million of unproved properties acquired that were recorded to the oil and natural gas properties full cost pool, thereby accelerating the costs subject to depletion.
The Partnership subsequently filed an acquisition shelf registration statement on Form S-4 that became effective June 6, 2019 and a shelf registration statement on Form S-3 that became effective August 21, 2019. 20,000,000 units remain available for issuance under the Partnership's registration statements.
3 Commitments and Contingencies: The Partnership and Dorchester Minerals Operating L.P., a Delaware limited partnership owned directly and indirectly by our general partner, are involved in legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on our consolidated financial position, cash flows, or operating results.
4 Distributions to Holders of Common Units: Unitholder cash distributions per common unit are as follows:
|
|
|
Per Unit Amount
|
|
|
|
|
2019
|
|
|
2018
|
|
|
First quarter
|
|
$
|
0.482315
|
|
|
$
|
0.418449
|
|
|
Second quarter
|
|
$
|
0.515016
|
|
|
$
|
0.537264
|
|
|
Third quarter
|
|
$
|
0.499055
|
|
|
$
|
0.394813
|
|
|
Fourth quarter
|
|
|
|
|
|
$
|
0.516572
|
|
Distributions beginning with the first quarter of 2019 were paid on 34,679,774 units and distributions in 2018 were paid on 32,279,774 units. The third quarter 2019 distribution will be paid on November 7, 2019. Fourth quarter distributions shown above are paid in the first calendar quarter of the following year. Our partnership agreement requires the fourth quarter cash distribution to be paid by February 14, 2020.
5 New Accounting Pronouncements: In February 2016, the Financial Standards Accounting Board (“FASB”) issued a new standard related to leases, Accounting Standards Codification (“ASC”) 842 – Leases (“ASC 842”) to increase transparency and comparability among organizations by requiring the recognition of right-of-use (“ROU”) assets and lease liabilities on the balance sheet, including the recognition of ROU assets and lease liabilities for operating leases. ASC 842 requires certain disclosures to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.
The Partnership adopted ASC 842 on January 1, 2019, using the modified retrospective transition method as of the adoption date, which did not require the Partnership to adjust comparative periods.
In addition, the Partnership elected the package of practical expedients permitted under the transition guidance within ASC 842, which among other things, allowed the Partnership to carry forward the historical lease classification. The Partnership also elected the land easements practical expedient, which allowed the Partnership to carry forward the accounting treatment for land easements on existing agreements.
The Partnership determines if an arrangement is a lease at inception. Upon lease commencement, the Partnership concluded its office lease was an operating lease and therefore, on January 1, 2019, the Partnership recognized a ROU asset of $1.9 million, excluding lease incentives, and a lease liability of $2.7 million related to its office lease. The difference between the ROU asset and operating lease liability was recorded as an adjustment to deferred rent incentive. The adoption of ASC 842 had no impact on Partnership capital, the consolidated statements of income or the consolidated statements of cash flows. In preparation for the adoption of ASC 842, the Partnership implemented internal controls to identify arrangements that may contain a lease.
6 Leases: The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease.
Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. As the Partnership’s lease does not provide an implicit rate of return and as the Partnership is precluded from incurring any borrowings above a nominal amount under its partnership agreement, the Partnership used a discount rate commensurate with the incremental borrowing rate of a group of peers based on information available at the adoption date in determining the present value of lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.
|
|
|
Three Months
Ended
|
|
|
Nine Months
Ended
|
|
|
|
|
|
September 30, 2019
|
|
|
September 30, 2019
|
|
CONDENSED CONSOLIDATED INCOME STATEMENTS
|
|
|
|
(In Thousands)
|
|
|
(In Thousands)
|
|
|
|
Lease Expense
|
|
|
|
|
|
|
|
|
|
|
Operating lease expense
|
|
$
|
66
|
|
|
$
|
198
|
|
General and administrative expenses
|
|
|
|
Nine Months Ended
|
|
|
|
|
September 30, 2019
|
|
|
|
|
(In Thousands)
|
|
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
|
|
|
Operating cash flows from operating leases
|
|
$
|
177
|
|
|
|
|
As of
|
|
|
|
|
September 30, 2019
|
|
|
|
|
|
|
|
|
Weighted-Average Remaining Lease Term (months)
|
|
|
|
|
|
Operating lease
|
|
|
113
|
|
|
|
|
|
|
|
|
Weighted-Average Discount Rate
|
|
|
|
|
|
Operating lease
|
|
|
5
|
%
|
Maturities of lease liabilities are as follows:
|
|
|
As of
|
|
|
|
|
September 30, 2019
|
|
|
|
|
(In Thousands)
|
|
|
2019
|
|
$
|
77
|
|
|
2020
|
|
|
332
|
|
|
2021
|
|
|
338
|
|
|
2022
|
|
|
344
|
|
|
2023
|
|
|
350
|
|
|
Thereafter
|
|
|
1,903
|
|
|
Total lease payments
|
|
|
3,344
|
|
|
Less amount representing interest
|
|
|
(774
|
)
|
|
Total lease obligation
|
|
$
|
2,570
|
|
|
item 2.
|
Management’s Discussion and Analysis of Financial Condition and Results of Operations
|
The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this quarterly report on Form 10-Q.
Overview
We own producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty properties. We currently own Royalty properties in 594 counties and parishes in 27 states.
We own six net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”), one of which was acquired on March 29, 2019 in connection with the Huffman Acquisition discussed below, in various properties owned by Dorchester Minerals Operating LP (the “Operating Partnership”), a Delaware limited partnership owned directly and indirectly by our general partner. We receive monthly payments equaling 96.97% of the net profits actually realized by the Operating Partnership from these properties in the preceding month. In the event that costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for properties subject to a Net Profits Interests, no payment is made and any deficit is accumulated and reflected in the following month's calculation of net profit.
Each of the six NPIs (including the Minerals NPI, which is our largest NPI) have previously had cumulative revenue that exceeded cumulative costs, such excess constituting net proceeds on which NPI payments were determined. In the event an NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership.
From a cash perspective, as of September 30, 2019, the Minerals NPI was in a surplus position and had outstanding capital commitments equaling cash on hand of $6.3 million.
Commodity Price Risks
Our profitability is affected by oil and natural gas market prices. Oil and natural gas market prices have fluctuated significantly in recent years in response to changes in the supply and demand for oil and natural gas in the market, along with domestic and international political and economic conditions.
Results of Operations
Huffman Acquisition
On March 29, 2019, the Partnership acquired (the “Huffman Acquisition”) producing and nonproducing mineral, royalty and net profits interests pursuant to a 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 “Contribution and Exchange Agreement”). 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 Trend 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 $1.4 million (including adjustments made post-closing). The contributing entities conveyed their interests to the Partnership and affiliates of its general partner in exchange for 2,400,000 common limited partnership units. The net income from the properties acquired and cash funds delivered in the Huffman Acquisition are included in the results of operations for the three and nine months ended September 30, 2019.
Three and Nine Months Ended September 30, 2019 as compared to Three and Nine Months Ended September 30, 2018
Our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were:
|
|
|
Three Months Ended
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
|
|
|
|
|
|
September 30,
|
|
|
|
|
|
|
September 30,
|
|
|
|
|
|
|
Accrual basis sales volumes:
|
|
2019
|
|
|
2018
|
|
|
% Change
|
|
|
2019
|
|
|
2018
|
|
|
% Change
|
|
|
Royalty properties natural gas sales (mmcf)
|
|
|
913
|
|
|
|
767
|
|
|
|
19
|
%
|
|
|
3,059
|
|
|
|
2,585
|
|
|
|
18
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty properties oil sales (mbbls)
|
|
|
260
|
|
|
|
206
|
|
|
|
26
|
%
|
|
|
796
|
|
|
|
608
|
|
|
|
31
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPI natural gas sales (mmcf)
|
|
|
719
|
|
|
|
702
|
|
|
|
2
|
%
|
|
|
2,063
|
|
|
|
1,963
|
|
|
|
5
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPI oil sales (mbbls)
|
|
|
123
|
|
|
|
148
|
|
|
|
(17
|
%)
|
|
|
390
|
|
|
|
339
|
|
|
|
15
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrual basis weighted average sales price:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty properties natural gas sales ($/mcf)
|
|
$
|
1.28
|
|
|
$
|
2.26
|
|
|
|
(43
|
%)
|
|
$
|
1.81
|
|
|
$
|
2.41
|
|
|
|
(25
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty properties oil sales ($/bbl)
|
|
$
|
48.85
|
|
|
$
|
54.23
|
|
|
|
(10
|
%)
|
|
$
|
48.84
|
|
|
$
|
55.68
|
|
|
|
(12
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPI natural gas sales ($/mcf)
|
|
$
|
1.21
|
|
|
$
|
2.24
|
|
|
|
(46
|
%)
|
|
$
|
1.87
|
|
|
$
|
2.28
|
|
|
|
(18
|
%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NPI oil sales ($/bbl)
|
|
$
|
47.87
|
|
|
$
|
56.83
|
|
|
|
(16
|
%)
|
|
$
|
45.97
|
|
|
$
|
56.55
|
|
|
|
(19
|
%)
|
Both oil and natural gas sales price changes reflected in the table above resulted from changing market conditions.
The increase in oil sales volumes attributable to our Royalty properties during the third quarter and first nine months of 2019 compared to the same periods of 2018 is primarily a result of increased Permian Basin and Bakken production. The increase in natural gas sales volumes attributable to our Royalty properties during the third quarter and first nine months of 2019 compared to the same periods of 2018 is primarily a result of increased production in the Permian Basin, Bakken, and East Texas, partially offset by decreased production in the Barnett Shale and Mid-Continent.
The decrease in oil sales volumes attributable to our NPIs during the third quarter of 2019 compared to the same period of 2018 is primarily a result of a lower number of new wells in the Bakken and Permian during the third quarter of 2019 versus the third quarter of 2018. The increase in oil sales volumes attributable to our NPIs during the first nine months of 2019 compared to the same period of 2018 is primarily a result of suspense releases for new wells and increased production in the Bakken. The increase in natural gas volumes attributable to our NPIs during the third quarter and first nine months of 2019 compared to the same periods of 2018 is primarily a result of suspense releases for new wells and increased production in the Bakken, partially offset by decreased production in the Fayetteville Shale.
Our third quarter lease bonus revenue increased 933% from $0.3 million during 2018 to $3.1 million during the same period of 2019. The increase is primarily attributable to receipt of lease bonuses from multiple leases consummated in various Texas counties during the third quarter of 2019. Our first nine months lease bonus revenue decreased 20% from $4.5 million during 2018 to $3.6 million during the same period of 2019. The decrease resulted from a transaction in the second quarter of 2018 assigning a non-producing leasehold interest recorded as lease bonus revenue as the Partnership retained an overriding royalty interest, partially offset by lease bonuses consummated during the third quarter of 2019.
Our third quarter net operating revenues increased 41% from $13.9 million during 2018 to $19.6 million during the same period of 2019. The increase is primarily due to higher Royalty, NPI, and lease bonus revenue. Net operating revenue for the first nine months increased 16% from $50.9 million during 2018 to $59.2 million during the same period of 2019. The increase is primarily a result of higher Royalty and NPI revenue, partially offset by lower lease bonus revenue.
Operating costs, including production taxes, remained consistent during the third quarter of 2019 compared to the same period of 2018. Operating costs, including production taxes, for the first nine months increased 20% from $4.0 million during 2018 to $4.8 million during the same period of 2019. The increase is primarily a result of higher production taxes and marketing costs due to higher oil and natural gas sales volumes, partially offset by lower oil and natural gas prices.
General and administrative expenses for the third quarter and first nine months of 2019 compared to the same periods of 2018 increased 89% from $0.9 million to $1.7 million and 17% from $3.5 million to $4.1 million, respectively. The increase is primarily a result of higher information technology project costs and payroll expense versus prior year.
Depreciation, depletion and amortization costs of $2.4 million during the third quarter of 2018 increased 50% to $3.6 million during the same period of 2019. Depreciation, depletion and amortization costs of $6.9 million during the first nine months of 2018 increased 43% compared to $9.9 million during the same period of 2019. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including acquisitions.
Third quarter net income allocable to common units increased 39% from $8.9 million during 2018 to $12.4 million during the same period of 2019. The increase is primarily due to higher Royalty, NPI, and lease bonus revenue, partially offset by higher general and administrative expenses and depreciation, depletion and amortization costs. Net income allocable to common units increased 11% from $35.3 million during the first nine months of 2018 to $39.1 million during the same period of 2019. The increase is primarily due to higher Royalty and NPI revenue, partially offset by lower lease bonus revenue and higher general and administrative expenses and depreciation, depletion and amortization costs.
Net cash provided by operating activities increased 17% from $46.7 million during the first nine months of 2018 to $54.8 million during the same period of 2019. The change is primarily driven by higher oil and natural gas sales volumes, partially offset by lower oil and natural gas prices. Net cash provided by investing activities increased $1.9 million primarily due to the cash contributed resulting from the acquisition of properties in the first quarter of 2019.
In an effort to provide the reader with information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the weighted 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 contract terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between our 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 purchasers’ prior period adjustments.
Cash receipts attributable to our Royalty properties during the third quarter of 2019 totaled $13.4 million. These receipts generally reflect oil sales during June 2019 through August 2019 and natural gas sales during May 2019 through July 2019. The weighted average indicated prices for oil and natural gas sales received during the third quarter of 2019 attributable to the Royalty properties were $48.73/bbl and $1.61/mcf, respectively.
Cash receipts attributable to our NPIs during the third quarter of 2019 totaled approximately $2.9 million. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during May 2019 through July 2019. The weighted average indicated prices for oil and natural gas sales received during the third quarter of 2019 attributable to our NPIs were $49.31/bbl and $1.62/mcf, respectively.
Liquidity and Capital Resources
Capital Resources
Our primary sources of capital are our cash flows from the NPIs and the Royalty properties. Our only cash requirements are the distributions to our unitholders, 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 our 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 most 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 Note 4 to the unaudited Condensed Consolidated Financial Statements included in Item 1 of this quarterly report on Form 10-Q for the amounts and dates of cash distributions to unitholders.
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 our 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).
Expenses and Capital Expenditures
The Operating Partnership continues to assess the opportunity to increase production based on prevailing market conditions in Oklahoma with techniques that may include fracture treating, deepening, recompleting, and drilling. Costs vary widely and are not predictable as each effort requires specific engineering. Such activities by the Operating Partnership could influence the amount we receive from the NPIs.
The Operating Partnership owns and operates the wells, pipelines and natural gas compression and dehydration facilities located in Oklahoma. The Operating Partnership does not anticipate incurring significant expense to replace these facilities at this time. These capital and operating costs are reflected in the NPI payments we receive from the Operating Partnership.
In 1998, Oklahoma regulations removed production quantity restrictions in the Guymon-Hugoton field and did not address efforts by third parties to persuade Oklahoma to permit infill drilling in the Guymon-Hugoton field. Infill drilling could require considerable capital expenditures. The outcome and the cost of such activities are unpredictable and could influence the amount we receive from the NPIs. The Operating Partnership believes it now has sufficient field compression and permits for vacuum operation for the foreseeable future.
Liquidity and Working Capital
Cash and cash equivalents totaled $21.9 million at September 30, 2019 and $18.3 million at December 31, 2018.
Critical Accounting Policies
As of September 30, 2019, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2018 Annual Report on Form 10-K, except for ASU No. 2016-02, Leases (Topic 842), as amended, which the Partnership adopted on January 1, 2019.
item 3. Quantitative and Qualitative Disclosures About Market Risk
The following information provides quantitative and qualitative information about our potential exposures to market risk. The term “market risk” refers to the risk of loss arising from adverse changes in oil and natural gas prices, interest rates and currency exchange rates. The disclosures are not meant to be precise indicators of expected future losses but, rather, indicators of possible losses.
Market Risk Related to Oil and Natural Gas Prices
Essentially all of our assets and sources of income are from Royalty properties and NPIs, which generally entitle us to receive a share of the proceeds based on oil and natural gas production from those properties. Consequently, we are subject to market risk from fluctuations in oil and natural gas prices. Pricing for oil and natural gas production has been unpredictable for several years. We do not anticipate entering into financial hedging activities intended to reduce our exposure to oil and natural gas price fluctuations.
Absence of Interest Rate and Currency Exchange Rate Risk
We do not anticipate having a credit facility or incurring any debt other than trade debt. Therefore, we do not expect interest rate risk to be material to us. We do not anticipate engaging in transactions in foreign currencies that could expose us to foreign currency related market risk.
item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective.
Changes in Internal Controls
There were no changes in our internal controls over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.