DORCHESTER MINERALS, L.P. - Quarter Report: 2015 September (Form 10-Q)

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, 2015

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)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer”, “accelerated filer” and “smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one):

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 5, 2015, 30,675,431 common units representing limited partnership interests were outstanding.

TABLE OF CONTENTS

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.

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED BALANCE SHEETS

(In Thousands)

The accompanying condensed notes are an integral part of these condensed consolidated financial statements.

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED INCOME STATEMENTS

(In Thousands except Income per Unit)

(Unaudited)

The accompanying condensed notes are an integral part of these condensed consolidated financial statements.

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In Thousands)

(Unaudited)

The accompanying condensed 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)

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

DORCHESTER MINERALS, L.P.

(A Delaware Limited Partnership)

The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this 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 net profits overriding royalty interests (referred to as the Net Profits Interests, or “NPIs”) in various properties owned by Dorchester Minerals Operating LP, a Delaware limited partnership owned directly and indirectly by our general partner. We refer to Dorchester Minerals Operating LP as the “operating partnership” or “DMOLP.” 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 costs exceed revenues on a cash basis in a given month for properties subject to a Net Profits Interest, no payment is made and any deficit is accumulated and carried over and reflected in the following month's calculation of net profit.

Each of the five NPIs 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.

Prior to initially achieving a cumulative payout status in the third quarter of 2011, the Minerals NPI’s activity was not reflected in our consolidated financial statements in accordance with generally accepted accounting principles (“GAAP”). Effective third quarter 2011, our consolidated financial statements reflect activity attributable to the Minerals NPI, and include cash receipts and disbursements and accrued revenues and costs not yet received or paid by the NPI. Our financial statements will continue to reflect such information even if the NPI is in temporary deficit due to capital expenditures. Minerals NPI production volumes and prices are within the consolidated financial statements in accordance with GAAP, although accrued net profits income in the third quarter and nine month period of 2014 and 2015 from this NPI is zero because accrued cumulative capital costs have exceeded accrued cumulative operating income.

Prior to the third quarter of 2015, the last payment attributable to the Minerals NPI was declared as of July 31, 2013, at which time cash on hand equaled outstanding capital commitments (resulting in a zero balance, i.e. neither a deficit nor surplus). Since that time, DMOLP has received production revenue, paid operating and capital expenses and made additional capital commitments, resulting in the temporary deficit on a GAAP basis described above. The Minerals NPI again achieved a cumulative surplus on a cash basis as of September 30, 2015. The payment attributable to the surplus will be reflected in the fourth quarter distribution. Set forth below is a summary calculation of this activity and the calculation of the Minerals NPI surplus as of September 30, 2015:

Commodity Price Risks

Our profitability is affected by oil and natural gas market prices. Oil and natural gas 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, 2015 as compared to Three and Nine Months Ended September 30, 2014

Normally, our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices. Our portion of oil and natural gas sales and weighted average prices were:

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 decreased 3% from 131 mbbls in 2014 to 127 mbbls in the same period of 2015. Oil sales volumes attributable to the first nine months increased slightly from 381 mbbls in 2014 to 385 mbbls in the same period of 2015. The decrease in volumes during the third quarter is a result of natural reservoir declines. Natural gas sales volumes attributable to our Royalty Properties during the third quarter increased 15% from 854 mmcf in 2014 to 980 mmcf in 2015. Natural gas sales volumes during the first nine months increased slightly from 2,702 mmcf in 2014 to 2,704 mmcf in 2015. The increase in natural gas sales volumes in the third quarter of 2015 compared to the same period of 2014 is primarily due to prior period adjustments in the mid-continent area.

Oil sales volumes attributable to our NPIs during the third quarter and first nine months of 2015 were 156 mbbls and 329 mbbls, resulting in increases of 136% and 107% from 66 mbbls and 159 mbbls during the same periods of 2014. The increases in oil sales volumes during both periods are a result of robust activity in the Bakken Trend and significant prior period adjustments in the third quarter of 2015. Natural gas sales volumes attributable to our NPIs during the third quarter increased 4% from 853 mmcf in 2014 to 884 mmcf in 2015 due to an increased number of payouts. During the first nine months of 2015, NPI natural gas sales volumes decreased 5% from 2,613 mmcf in 2014 to 2,483 mmcf in 2015. The decrease was primarily due to natural reservoir declines in the Fayetteville Shale and the sale of Kansas working interests during the third quarter of 2014.

Our third quarter and first nine months net operating revenues decreased 53% and 52% from $15,716,000 and $51,028,000 during 2014 to $7,387,000 and $24,471,000 during 2015, respectively. These decreases are primarily a result of changes in prices along with decreased lease bonus income in 2015.

Third quarter and first nine months costs and expenses decreased 1% and 8% from $4,751,000 and $15,205,000 during 2014 to $4,706,000 and $13,946,000 during 2015, respectively. The decreases are primarily a result of lower production taxes and lower ad valorem taxes due to lower oil and natural gas sales prices.

General and administrative expenses of $1,065,000 and $3,488,000 during the third quarter and first nine months of 2015 increased 34% and 17% compared to $796,000 and $2,991,000, respectively, during the same periods of 2014. The increases are primarily due to added compensation expense for new hires and outsourcing of information technology services.

Depletion and amortization costs of $3,048,000 during the third quarter of 2015 increased 17% compared to $2,610,000 during the third quarter of 2014. The increase is primarily due to significant prior period adjustments in the third quarter of 2015. Depletion and amortization costs of $7,854,000 during the first nine months of 2015 decreased slightly compared to $7,893,000 during the first nine months of 2014.

Other income of $712,000 during the first nine months of 2014 was primarily related to a first quarter 2014 settlement of a dispute on leases in North Dakota.

Third quarter and first nine months net income allocable to common units decreased 76% and 71% from $10,569,000 and $35,219,000 during 2014 to $2,580,000 and $10,125,000, respectively, during 2015. The decrease is due to lower oil and natural gas sales prices and lower lease bonus income, partially offset by increased oil volumes.

Net cash provided by operating activities decreased 52% from $47,009,000 during the first nine months of 2014 to $22,476,000 during the same period of 2015. The decrease is due to lower oil and natural gas sales prices and decreased lease bonus income.

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 2015 third quarter totaled approximately $7,100,000. These receipts generally reflect oil sales during June through August 2015 and natural gas sales during May through July 2015. The weighted average indicated prices for oil and natural gas sales received during the 2015 third quarter attributable to the Royalty Properties were $43.40/bbl and $2.34/mcf, respectively.

Cash receipts attributable to our NPIs during the 2015 third quarter totaled approximately $400,000. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during May through July 2015. The weighted average indicated prices for oil and natural gas sales received during the 2015 third quarter attributable to our NPIs were $50.84/bbl and $2.71/mcf, respectively.

Information concerning selected properties is summarized below:

Horizontal Bakken, Williston Basin – We own varying undivided perpetual mineral interests in approximately 70,000/9,000 gross/net acres located in Burke, Divide, Dunn, McKenzie, Mountrail and Williams Counties, North Dakota. Permits for 698 wells had been issued on these lands as of September 30, 2015. In total, 618 wells were spud, of which 552 were completed as producers including wells for which we may not yet have received division orders or first payment. In some instances we elected to become a non-consenting mineral owner—who, according to North Dakota law, is not obligated to pay well costs, receives a royalty equal to the weighted average of all leases in the unit or 16% (at the operator’s option) from the date of first production, and backs-in for its full working interest after the operator has recovered 150% of drilling and completion costs from the net cash flow. The back-in working interest, if any, is owned by the operating partnership subject to the Minerals NPI burden. Non-consenting mineral owners are not entitled to well data other than public information available from the North Dakota Industrial Commission. As of September 30, 2015, 45 of these wells had achieved 150% payout.

We have and will continue to utilize a range of transaction structures for our unleased mineral interests including leasing to third parties, working interest participation through the operating partnership, electing non-consent under North Dakota law, or a combination thereof.

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 in accordance with our partnership agreement. Since 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 payments of expenses. Since 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 of the Notes to the Condensed Consolidated Financial Statements 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

Depending upon gas prices, the operating partnership plans to continue its efforts to increase production 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 as reflected in the accrual-basis production costs $/mcfe in the table under “Results of Operations.”

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 $8,113,000 at September 30, 2015 and $15,912,000 at December 31, 2014.

Critical Accounting Policies

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, however, 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 full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment.

The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers may reach different conclusions as to estimated quantities of natural gas or crude oil reserves based on the same information. Our reserve estimates are prepared by independent consultants. The passage of time provides more qualitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can be no assurance that significant revisions will not be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of the first day of the month price during the 12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the properties. As a result, the present value is not necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile and the prevailing prices at any given time may not reflect our Partnership’s or the industry’s forecast of future prices.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America 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 NPI properties 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.

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.

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, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II – OTHER INFORMATION

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.

See the attached Index to Exhibits. 

SIGNATURES

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.

INDEX TO EXHIBITS

* Filed herewith

**Furnished herewith