DORCHESTER MINERALS, L.P. - Quarter Report: 2014 March (Form 10-Q)

2       Contingencies: 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.

3       Distributions to Holders of Common Units: Unitholder cash distributions per common unit since 2010 have been:

Distributions beginning with the first quarter of 2010 were paid on 30,675,431 units. The first quarter 2014 distribution was paid on May 1, 2014. Fourth quarter distributions shown above are paid in the first calendar quarter of the following year. Our partnership agreement requires the next cash distribution to be paid by August 15, 2014.

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 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 the Minerals NPI (one of the five NPIs) achieving a cumulative payout status, activity attributable to the Minerals NPI 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 now continue to reflect such information regardless of its net profit status on a cumulative or reporting period basis. As of March 31, 2014, the Minerals NPI is currently in temporary deficit of $7,900,000, primarily due to budgeted capital expenditures.

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 Months Ended March 31, 2014 as compared to Three Months Ended March 31, 2013

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:

As of January 1, 2014 we adopted a change in the methodology used to account for plant products volumes. These products were previously converted into a natural gas equivalent volume, but will now be converted into a liquid equivalent volume. As a result, volumes attributable to such products will no longer contribute to natural gas sales volumes, but will instead be included with oil sales volumes. This change in methodology will affect reported results effective as of January 1, 2014, including a reduction in accrued gas equivalent volumes for Royalty and NPI properties of 182 mmcfe and 49 mmcfe, respectively, and an increase in accrued oil equivalent volumes for Royalty and NPI properties of 12 mbbls and 3 mbbls, respectively. This change in methodology was recommended by our independent reserve engineers and we feel it more accurately reflects the underlying character of our plant products and their contribution to our production results.

Natural gas sales volumes attributable to our Royalty Properties during the first quarter decreased 35.5% from 1,277 mmcf in 2013 to 823 mmcf in 2014. The decrease in natural gas sales volumes in the first quarter compared to the same period of 2013 is primarily due to the above mentioned change in accounting for plant products and natural reservoir declines. Oil sales volumes attributable to our Royalty Properties during the first quarter increased 42.5% from 87 mbbls in 2013 to 124 mbbls in 2014. The increase in oil sales volumes are a result of the above mentioned change in accounting for plant products and robust activity in the Permian Basin and the Bakken Trend.

Natural gas sales volumes attributable to our NPIs during the first quarter of 2014 were 843 mmcf, a decrease of 21.0% from 1,067 mmcf in the same period of 2013. The decrease was primarily due to the above mentioned change in accounting for plant products and natural reservoir declines in the Fayetteville Shale. Oil sales volumes attributable to our NPIs during the first quarter of 2014 were 48 mbbls, an increase of 128.6% from 21 mbbls during the same period of 2013. The increase in oil sales volumes are a result of the above mentioned change in accounting for plant products and robust activity in the Permian Basin and the Bakken Trend.

The weighted average oil sales prices attributable to our interest in Royalty Properties decreased 4.4% from $87.72/bbl during the first quarter of 2013 to $83.85/bbl during the first quarter of 2014. Weighted average natural gas sales prices from Royalty Properties increased 66.1% from $3.10/mcf during the first quarter of 2013 to $5.15/mcf during the first quarter of 2014. Both oil and natural gas price changes resulted from changing market prices.

First quarter weighted average oil sales prices from the NPIs remained about the same at $87.89/bbl in 2014 compared to $88.89/bbl in 2013. First quarter weighted average natural gas sales prices attributable to the NPIs increased 70.1% from $3.35/mcf during 2013 to $5.70/mcf in 2014. Both oil and natural gas price changes resulted from changing market prices.

Our first quarter net operating revenues increased 31.2% from $13,218,000 during 2013 to $17,339,000 during 2014. This increase is primarily a result of increased prices as discussed above and increased lease bonus income.

Costs and expenses of $5,092,000 during the first quarter of 2014 were down 8.6% compared to $5,570,000 during the first quarter of 2013. First quarter 2014 increased general and administrative costs and production taxes on higher revenues were offset by reduced ad valorem costs and depletion and amortization costs compared to the first quarter of 2013.

General and administrative expenses of $1,136,000 during the first quarter of 2014 were up 26.4% compared to $899,000 during the same period of 2013, primarily due to costs related to the Bakken Trend and the Fayetteville Shale.

Depletion and amortization costs of $2,517,000 during the first quarter of 2014 were down 25.7% compared to $3,386,000 during the same period of 2013. The reduction was due to the effects of upward reserve revisions at 2013 year-end and lower natural gas sales volumes during 2014.

Other income of $650,000 during the first quarter of 2014 was related to settlement of a dispute on leases in North Dakota.

First quarter net income allocable to common units increased 68.7% from $7,374,000 during 2013 to $12,442,000 during 2014. Increased oil and natural gas sales prices, oil volumes, and lease bonus income were partially offset by increased capital costs and commitments by the operating partnership for drilling activities on properties underlying the NPIs, and decreased natural gas sales volumes.

Net cash provided by operating activities increased 11.3% from $14,635,000 during the first quarter of 2013 to $16,290,000 during the first quarter of 2014. The increase is due to changes in oil and natural gas prices and volumes and increased lease bonus income. These increases were partially offset by capital costs and commitments for drilling activities on the properties underlying the NPI properties.

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 2014 first quarter totaled approximately $13,100,000. These receipts generally reflect oil sales during December 2013 through February 2014 and natural gas sales during November 2013 through January 2014. The weighted average indicated prices for oil and natural gas sales received during the 2014 first quarter attributable to the Royalty Properties were $84.98/bbl and $4.11/mcf, respectively.

Cash receipts attributable to our NPIs during the 2014 first quarter totaled approximately $3,600,000. These receipts generally reflect oil and natural gas sales from the properties underlying the NPIs during November 2013 through January 2014. The weighted average indicated prices for oil and natural gas sales received during the 2014 first quarter attributable to our NPIs were $86.85/bbl and $7.43/mcf, respectively. The natural gas weighted average indicated price for the quarter was increased by $3.29/mcf due to the receipt of a natural gas liquids payment of $2,000,000 for 2013 production. The natural gas liquids payment is based on an Oklahoma Guymon-Hugoton field 1994 gas delivery agreement that is in effect through 2015. Under the terms of the agreement, when the market price of natural gas liquids increases sufficiently disproportionately to natural gas market prices, the operating partnership receives a portion of that increase in an annual payment based on calendar year data. In the event the evaluation at the end of the annual contract period shows the payment to be determinable and collectable, the revenue is accrued.

Information concerning selected properties is summarized below:

APPALACHIAN BASIN   – We own varying undivided perpetual mineral interests in approximately 31,000/24,000 gross/net acres in 19 counties in southern New York and northern Pennsylvania. Approximately 75% of those net acres are located in eastern Allegany and western Steuben Counties, New York—an area that some industry press reports suggest may be prospective for gas production from unconventional reservoirs, including the Marcellus Shale. However, development of these natural gas resources will be limited until remaining regulatory issues related to high-volume hydraulic fracturing are resolved. We continue to monitor industry activity and encourage dialogue with industry participants to determine the proper course of action regarding our interests in this area.

FAYETTEVILLE SHALE TREND OF NORTHER ARKANSAS   –   We own varying undivided perpetual mineral interests in approximately 23,000/11,000 gross/net acres located in Cleburne, Conway, Faulkner, Franklin, Johnson, Pope, Van Buren, and White counties, Arkansas in an area commonly referred to as the “Fayetteville Shale” trend of the Arkoma Basin. Permits for 497 wells had been issued on these lands as of March 31, 2014, of which the operating partnership owns an interest in 248. In total, 484 wells were spud of which 446 were completed as producers, including wells for which we may not yet have received division orders or first payment.   

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 528 wells had been issued on these lands as of March 31, 2014. In total, 460 wells were spud, of which 377 were completed as producers including wells for which we may not yet have received division orders or first payment. In most 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 March 31, 2014, 36 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 Kansas and 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 $16,531,000 at March 31, 2014 and $15,175,000 at December 31, 2013.

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 March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

 

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PART II – OTHER INFORMATION

 

Item 1.          Legal Proceedings

 

 

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.

 

 

Item 6.          Exhibits

 

See the attached Index to Exhibits.

  

 

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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.

 

 

	DORCHESTER MINERALS, L.P.
	By:	Dorchester Minerals Management LP
		its General Partner
	By:	Dorchester Minerals Management GP LLC
		its General Partner

 

	By:	/s/ William Casey McManemin
		William Casey McManemin
Date: May 8, 2014		Chief Executive Officer

 

	By:	/s/ H.C. Allen, Jr.
		H.C. Allen, Jr.
Date: May 8, 2014		Chief Financial Officer

 

 

 

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INDEX TO EXHIBITS

Number		Description
3.1		Certificate of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.1 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.2		Amended and Restated Agreement of Limited Partnership of Dorchester Minerals, L.P. (incorporated by reference to Exhibit 3.2 to Dorchester Minerals’ Report on Form 10-K filed for the year ended December 31, 2002)
3.3		Certificate of Limited Partnership of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.4		Amended and Restated Limited Partnership Agreement of Dorchester Minerals Management LP (incorporated by reference to Exhibit 3.4 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
3.5		Certificate of Formation of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.7 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.6		Amended and Restated Limited Liability Company Agreement of Dorchester Minerals Management GP LLC (incorporated by reference to Exhibit 3.6 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
3.7		Certificate of Formation of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.8		Limited Liability Company Agreement of Dorchester Minerals Operating GP LLC (incorporated by reference to Exhibit 3.11 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.9		Certificate of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.12 to Dorchester Minerals’ Registration Statement on Form S-4, Registration Number 333-88282)
3.10		Amended and Restated Agreement of Limited Partnership of Dorchester Minerals Operating LP (incorporated by reference to Exhibit 3.10 to Dorchester Minerals’ Report on Form 10-K for the year ended December 31, 2002)
31.1*		Certification of Chief Executive Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
31.2*		Certification of Chief Financial Officer of the Partnership pursuant to Rule 13a-14(a) of the Securities Exchange Act of 1934
32.1**		Certification of Chief Executive Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350
32.2**		Certification of Chief Financial Officer of the Partnership pursuant to 18 U.S.C. Sec. 1350 (contained within Exhibit 32.1 hereto)
101.INS**		XBRL Instance Document
101.SCH**		XBRL Taxonomy Extension Schema Document
101.CAL**		XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**		XBRL Taxonomy Extension Definition Document
101.LAB**		XBRL Taxonomy Extension Label Linkbase Document
101.PRE**		XBRL Taxonomy Extension Presentation Linkbase Document

* Filed herewith

**Furnished herewith