Attached files
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| EX-32.1 - EXHIBIT 32.1 - DORCHESTER MINERALS, L.P. | ex_126474.htm |
| EX-31.2 - EXHIBIT 31.2 - DORCHESTER MINERALS, L.P. | ex_126473.htm |
| EX-31.1 - EXHIBIT 31.1 - DORCHESTER MINERALS, L.P. | ex_126472.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2018
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission file number 000-50175
DORCHESTER MINERALS, L.P.
(Exact name of registrant as specified in its charter)
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Delaware (State or other jurisdiction of incorporation or organization) |
81-0551518 (I.R.S. Employer Identification No.) |
3838 Oak Lawn Avenue, Suite 300, Dallas, Texas 75219
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (214) 559-0300
None
(Former name, former address and former fiscal year, if changed since last report)
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 (232.405 of this chapter) 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):
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Large accelerated filer ☐ |
Accelerated filer ☒ |
Non-accelerated filer ☐ |
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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 Act.): Yes ☐ No ☒
As of November 1, 2018, 32,279,774 common units representing limited partnership interests were outstanding.
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ITEM 1. |
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CONDENSED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2018 AND DECEMBER 31, 2017 (UNAUDITED) |
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ITEM 2. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
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ITEM 3. |
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ITEM 4. |
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ITEM 1. |
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ITEM 6. |
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DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
Statements included in this report that are not historical facts (including any statements concerning plans and objectives of management for future operations or economic performance, or assumptions or forecasts related thereto), are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward-looking” information. In this report, the term “Partnership,” as well as the terms “DMLP,” “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.
These forward-looking statements are based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and, therefore, involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons. Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations. These and other factors are set forth in our filings with the Securities and Exchange Commission.
You should read these statements carefully because they discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other “forward-looking” information. Before you invest, you should be aware that the occurrence of any of the events described in this report could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.
PART I – FINANCIAL INFORMATION
See attached financial statements on the following pages.
(A Delaware Limited Partnership)
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands)
(Unaudited)
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September 30, |
December 31, |
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2018 |
2017 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ | 15,703 | $ | 13,827 | ||||
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Trade and other receivables |
5,554 | 6,198 | ||||||
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Net profits interests receivable - related party |
4,327 | 5,330 | ||||||
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Total current assets |
25,584 | 25,355 | ||||||
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Property and leasehold improvements - at cost: |
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Oil and natural gas properties (full cost method) |
363,205 | 363,186 | ||||||
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Accumulated full cost depletion |
(304,275 |
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(297,442 |
) |
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Total |
58,930 | 65,744 | ||||||
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Leasehold improvements |
1,614 | 1,573 | ||||||
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Accumulated amortization |
(656 |
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(625 |
) |
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Total |
958 | 948 | ||||||
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Total assets |
$ | 85,472 | $ | 92,047 | ||||
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LIABILITIES AND PARTNERSHIP CAPITAL |
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Current liabilities: |
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Accounts payable and other current liabilities |
$ | 2,074 | $ | 599 | ||||
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Current portion of deferred rent incentive |
65 | 38 | ||||||
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Total current liabilities |
2,139 | 637 | ||||||
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Deferred rent incentive less current portion |
724 | 664 | ||||||
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Total liabilities |
2,863 | 1,301 | ||||||
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Commitments and contingencies (Note 2) |
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Partnership capital: |
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General partner |
1,690 | 1,782 | ||||||
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Unitholders |
80,919 | 88,964 | ||||||
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Total partnership capital |
82,609 | 90,746 | ||||||
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Total liabilities and partnership capital |
$ | 85,472 | $ | 92,047 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
(A Delaware Limited Partnership)
CONDENSED CONSOLIDATED INCOME STATEMENTS
(In Thousands except Income per Unit)
(Unaudited)
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Three Months Ended |
Nine Months Ended |
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| September 30, |
September 30, |
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2018 |
2017 |
2018 |
2017 |
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Net operating revenues: |
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Royalties |
$ | 12,889 | $ | 11,499 | $ | 40,076 | $ | 32,611 | ||||||||
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Net profits interests |
430 | 737 | 5,989 | 2,706 | ||||||||||||
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Lease bonus |
306 | 43 | 4,469 | 1,799 | ||||||||||||
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Other |
313 | 201 | 410 | 644 | ||||||||||||
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Total net operating revenues |
13,938 | 12,480 | 50,944 | 37,760 | ||||||||||||
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Costs and expenses: |
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Operating, including production taxes |
1,396 | 1,320 | 3,968 | 3,358 | ||||||||||||
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Depreciation, depletion and amortization |
2,396 | 2,795 | 6,864 | 6,443 | ||||||||||||
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General and administrative expenses |
867 | 1,141 | 3,506 | 3,764 | ||||||||||||
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Total costs and expenses |
4,659 | 5,256 | 14,338 | 13,565 | ||||||||||||
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Net income |
$ | 9,279 | $ | 7,224 | $ | 36,606 | $ | 24,195 | ||||||||
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Allocation of net income: |
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General partner |
$ | 361 | $ | 273 | $ | 1,311 | $ | 903 | ||||||||
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Unitholders |
$ | 8,918 | $ | 6,951 | $ | 35,295 | $ | 23,292 | ||||||||
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Net income per common unit (basic and diluted) |
$ | 0.27 | $ | 0.22 | $ | 1.09 | $ | 0.75 | ||||||||
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Weighted average basic and diluted common units outstanding |
32,280 | 32,280 | 32,280 | 31,222 | ||||||||||||
The accompanying notes are an integral part of these condensed consolidated financial statements.
(A Delaware Limited Partnership)
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Thousands)
(Unaudited)
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Nine Months Ended |
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September 30, |
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2018 |
2017 |
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Net cash provided by operating activities |
$ | 46,685 | $ | 31,274 | ||||
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Cash flows (used in) provided by investing activities: |
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Cash contributed (used) in acquisition of royalty interests |
(25 |
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437 | |||||
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Capital expenditures |
(41 |
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(106 |
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Total cash flows (used in) provided by investing activities |
(66 |
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331 | |||||
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Cash flows used in financing activities: |
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Distributions paid to general partner and unitholders |
(44,743 |
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(28,260 |
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Increase in cash and cash equivalents |
1,876 | 3,345 | ||||||
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Cash and cash equivalents at beginning of period |
13,827 | 8,212 | ||||||
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Cash and cash equivalents at end of period |
$ | 15,703 | $ | 11,557 | ||||
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Non-cash investing and financing activities: |
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Fair value of common units issued for acquisition of royalty interests |
$ | - | $ | 23,183 | ||||
The accompanying notes are an integral part of these condensed consolidated financial statements
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
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 Dorchester Minerals, L.P. and its wholly-owned subsidiaries Dorchester Minerals Oklahoma LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, and Dorchester-Maecenas 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 the 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 2017 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 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.
In June 2017, the Partnership acquired an undivided interest in certain mineral and royalty interests in exchange for 1,604,343 common units issued pursuant to the Partnership’s registration statements on Form S-4.
In April 2018, the Partnership and affiliates of its general partner consummated and closed a transaction assigning a non-producing leasehold interest and related NPI located in Upton County, Texas to a third party. The Partnership’s share of proceeds from the transaction was $4.0 million, recorded as lease bonus revenue.
2 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.
Operating Leases - The third amendment to our office lease was executed in April 2017, for a term of 129 months beginning June 1, 2018. The lease is for our office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, and expires in 2029. Under the third amendment to the office lease, monthly rental payments will range from $25,000 - $30,000.
3 Distributions to Holders of Common Units: Unitholder cash distributions per common unit are as follows:
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Per Unit Amount |
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2018 |
2017 |
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First quarter |
$ | 0.418449 | $ | 0.306700 | ||||
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Second quarter |
$ | 0.537264 | $ | 0.322965 | ||||
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Third quarter |
$ | 0.394813 | $ | 0.284650 | ||||
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Fourth quarter |
$ | 0.386915 | ||||||
Distributions beginning with the second quarter of 2017 were paid on 32,279,774 units; previous distributions set forth above were paid on 30,675,431 units. The third quarter 2018 distribution will be paid on November 8, 2018. 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, 2019.
4 New Accounting Pronouncements: In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (“ASU 2014-09”), which supersedes nearly all existing revenue recognition guidance under U.S. GAAP. The guidance requires entities to recognize revenue using the following five-step model: identify the contract with a customer, identify the performance obligations in the contract, determine the transaction price, allocate the transaction price to the performance obligations in the contract, and recognize revenue as the entity satisfies each performance obligation.
On January 1, 2018, we adopted ASU 2014-09 using the full retrospective method. The Partnership completed its review of a representative sample of revenue contracts covering its material revenue streams and determined that there is no impact to its consolidated financial statements, results of operations or liquidity. When comparing the Partnership’s historical revenue recognition to the newly applied revenue recognition under Accounting Standards Codification (“ASC”) 606, there was no change to the amount or timing of revenue recognized. Therefore, no quantitative adjustment was required to be made to the prior periods presented in these unaudited condensed consolidated financial statements after the adoption of ASC 606.
Accounting Policy – 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. Accordingly, the Partnership has not recorded any contract assets or contract liabilities as of September 30, 2018.
In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842), (“ASU 2016-02”) as updated by ASU 2018-10, Codification Improvements to Topic 842, Leases, which requires lessees to record most leases on the balance sheet. Under the new guidance, lease classification as either a finance lease or an operating lease will determine how lease-related revenue and expense are recognized. The guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. The new guidance does not apply to leases to explore for or use minerals, oil, natural gas and similar resources. The Partnership has an office lease commitment of $3.0 million that we believe would be subject to capitalization under ASU 2016-02. The lease obligations that will be in place upon adoption of ASU 2016-02 may be significantly different than our current obligations. We are still evaluating the impact of ASU 2016-02 on our consolidated financial statements.
In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”). ASU 2018-01 affects entities with land easements that exist or expired before an entity’s adoption of FASB ASC 842 – Leases (“ASC 842”). ASU 2018-01 provides an optional transition practical expedient to not evaluate under ASC 842 land easements that exist or expired before the entity’s adoption of ASC 842 and that were not previously accounted for as leases under ASC 840 – Leases. An entity that elects the practical expedient will be required to evaluate new or modified land easement arrangements under ASC 842 upon adoption of ASC 842. The Partnership will elect the practical expedient available under ASU 2018-01 and will apply the provisions of ASC 842 prospectively to all new or modified land easement arrangements.
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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 574 counties and parishes in 25 states.
We own five net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”) 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 five 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 temporary 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, 2018, the Minerals NPI was in a deficit position and had outstanding capital commitments of $14.8 million, exceeding cash on hand of $10.8 million. This is due to recent capital commitments in the Bakken region.
Commodity Price Risks
Our profitability is affected by oil and natural gas market prices. Oil and natural gas market prices have fluctuated significantly in recent years in response to changes in the supply and demand for oil and natural gas in the market, along with domestic and international political and economic conditions.
Results of Operations
Three and Nine Months Ended September 30, 2018 as compared to Three and Nine Months Ended September 30, 2017
Our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were:
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Three Months Ended |
Nine Months Ended |
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September 30, |
September 30, |
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Accrual basis sales volumes: |
2018 |
2017 |
2018 |
2017 |
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Royalty properties gas sales (mmcf) |
767 | 967 | 2,585 | 2,681 | ||||||||||||
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Royalty properties oil sales (mbbls) |
206 | 207 | 608 | 569 | ||||||||||||
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NPI gas sales (mmcf) |
702 | 631 | 1,963 | 1,799 | ||||||||||||
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NPI oil sales (mbbls) |
148 | 60 | 339 | 200 | ||||||||||||
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Accrual basis weighted average sales price: |
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Royalty properties gas sales ($/mcf) |
$ | 2.26 | $ | 2.63 | $ | 2.41 | $ | 2.94 | ||||||||
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Royalty properties oil sales ($/bbl) |
$ | 54.23 | $ | 43.32 | $ | 55.68 | $ | 43.46 | ||||||||
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NPI gas sales ($/mcf) |
$ | 2.24 | $ | 2.34 | $ | 2.28 | $ | 2.62 | ||||||||
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NPI oil sales ($/bbl) |
$ | 56.83 | $ | 41.51 | $ | 56.55 | $ | 40.30 | ||||||||
Both oil and natural gas sales price changes reflected in the table above resulted from changing market conditions.
Oil sales volumes attributable to our Royalty properties during the third quarter remained constant from 207 mbbls in 2017 to 206 mbbls in the same period of 2018. Oil sales volumes attributable to the first nine months of 2018 increased 7% to 608 mbbls from 569 mbbls in the same period of 2017. The increase in sales volumes during the first nine months of 2018 compared to the same period of 2017 is mainly a result of increased Permian Basin and Bakken production. Natural gas sales volumes attributable to our Royalty properties during the third quarter decreased 21% from 967 mmcf in 2017 to 767 mmcf in the same period of 2018. Natural gas sales volumes during the first nine months decreased 4% from 2,681 mmcf in 2017 to 2,585 mmcf in the same period of 2018. The decrease in sales volumes during the third quarter of 2018 compared to the same period of 2017 is mainly a result of decreased production in the Fayetteville Shale. The slight decrease in sales volumes during the first nine months of 2018 compared to the same period of 2017 is mainly a result of increased production in the Permian Basin offset by decreased production in the Fayetteville Shale.
Oil sales volumes attributable to our NPIs during the third quarter and first nine months of 2017 were 60 mbbls and 200 mbbls, respectively, resulting in increases of 147% and 70% to 148 mbbls and 339 mbbls during the same periods of 2018. Increases in oil sales volumes during the third quarter and first nine months of 2018 compared to the same periods of 2017 is mainly due to new Bakken and Permian Basin well activity. Natural gas sales volumes attributable to our NPIs during the third quarter increased 11% from 631 mmcf in 2017 to 702 mmcf in the same period of 2018. During the first nine months of 2018, NPI natural gas sales volumes increased 9% from 1,799 mmcf in 2017 to 1,963 mmcf in the same period of 2018. The increase in natural gas sales volumes is mainly due to higher amount of Permian Basin production in the first nine months of 2018 as compared to the first nine months of 2017.
The nine months ended lease bonus revenue increased 150% from $1.8 million during 2017 to $4.5 million during 2018. The increase is primarily a result of 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.
The third quarter net operating revenues increased 11% from $12.5 million during 2017 to $13.9 million during the same period of 2018. This increase in net operating revenues is primarily due to higher oil prices partially offset by a decrease in NPI income. The first nine months net operating revenues increased 35% from $37.8 million during 2017 to $51.0 million during the same period of 2018. This increase is primarily a result of higher oil prices realized in both our Royalty and NPI revenues, and higher lease bonus revenues.
Third quarter operating costs, including production taxes, increased 8% from $1.3 million in 2017 to $1.4 million in 2018. The first nine months operating costs increased 18% from $3.4 million during 2017 to $4.0 million during the same period of 2018. The increases in both periods are primarily a result of higher production taxes due to higher oil prices.
General and administrative expenses decreased by 24% from $1.1 million to $0.9 million during the third quarter of 2018 compared to the same period of 2017. General and administrative expenses also decreased by 7% from $3.8 million to $3.5 million during the first nine months of 2018 compared to the same period of 2017. Decreases as compared to both periods of 2017 were mainly driven by completion of our 2017 remodel.
Depletion and amortization costs of $2.8 million during the third quarter of 2017 decreased 14% to $2.4 million during the same period of 2018. Depletion and amortization costs of $6.4 million during the first nine months of 2017 increased 8% compared to $6.9 million during the same period of 2018. We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves.
Third quarter net income allocable to common units increased 27% from $7.0 million during 2017 to $8.9 million during the same period of 2018. The first nine months net income allocable to common units increased by 52% from $23.3 million in 2017 compared to $35.3 million during the same period of 2018. The increase in the third quarter of 2018 compared to the same period of 2017 is primarily due to higher royalty income due to higher oil prices. The increase in the first nine months of 2018 compared to the same period of 2017 is mainly due to higher royalty and NPI income due to higher oil prices and sales volumes in addition to higher lease bonus revenues.
Net cash provided by operating activities increased 49% from $31.3 million during the first nine months of 2017 to $46.7 million during the same period of 2018. The change is mainly driven by higher oil sales prices. Net cash provided by investing activities decreased $0.4 million due to the cash contributed with the acquisition of royalty interests in 2017.
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 2018 totaled $13.6 million. These receipts generally reflect oil sales during June 2018 through August 2018 and natural gas sales during May 2018 through July 2018. The weighted average indicated prices for oil and natural gas sales received during the third quarter of 2018 attributable to the Royalty properties were $55.71/bbl and $2.29/mcf, respectively.
Cash receipts attributable to our NPIs during the third quarter of 2018 totaled approximately $0.4 million. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during May 2018 through July 2018. The weighted average indicated prices for oil and natural gas sales received during the third quarter of 2018 attributable to our NPIs were $40.60/bbl and $2.03/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 3 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 $15.7 million at September 30, 2018 and $13.8 million at December 31, 2017.
Critical Accounting Policies
As of September 30, 2018, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our 2017 Annual Report on Form 10-K, except for Accounting Standards Update (ASU) No. 2014-09, Revenue from Contracts with Customers (ASU 2014-09), which was implemented in 2018.
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 (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended September 30, 2018 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
The Partnership and the operating partnership 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 consolidated financial position, cash flows, or operating results.
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3.1 |
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3.5 |
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3.9 |
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3.10 |
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3.11 |
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3.12 |
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31.1* |
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31.2* |
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32.1** |
Certification of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 |
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32.2** |
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101.INS** |
XBRL Instance Document |
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101.SCH** |
XBRL Taxonomy Extension Schema Document |
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101.CAL** |
XBRL Taxonomy Extension Calculation Linkbase Document |
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101.DEF** |
XBRL Taxonomy Extension Definition Document |
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101.LAB** |
XBRL Taxonomy Extension Label Linkbase Document |
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101.PRE** |
XBRL Taxonomy Extension Presentation Linkbase Document |
* Filed herewith
**Furnished herewith
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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DORCHESTER MINERALS, L.P. |
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By: |
Dorchester Minerals Management LP |
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its General Partner |
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By: |
Dorchester Minerals Management GP LLC |
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its General Partner |
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By: |
/s/ William Casey McManemin |
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William Casey McManemin |
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Date: November 1, 2018 |
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Chief Executive Officer |
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By: |
/s/ Leslie Moriyama |
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Leslie Moriyama |
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Date: November 1, 2018 |
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Chief Financial Officer |
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