DORCHESTER MINERALS, L.P. - Quarter Report: 2012 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, 2012
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)
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81-0551518
(I.R.S. Employer Identification No.)
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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 x No o
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 x No o
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):
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Large accelerated filer x
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Accelerated filer ¨
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Non-accelerated filer o
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Smaller reporting company o
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(Do not check if a smaller reporting company)
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act.): Yes o No x
As of November 8, 2012, 30,675,431 common units representing limited partnership interests were outstanding.
TABLE OF CONTENTS
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DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
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1
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PART I – FINANCIAL INFORMATION
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1
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ITEM 1.
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FINANCIAL STATEMENTS
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1
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CONDENSED CONSOLIDATED BALANCE SHEETS AS OF SEPTEMBER 30, 2012 (UNAUDITED) AND DECEMBER 31, 2011
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2
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CONDENSED CONSOLIDATED INCOME STATEMENTS FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011 (UNAUDITED)
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3
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CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2012 AND 2011 (UNAUDITED)
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4
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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
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5
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ITEM 2.
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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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6
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ITEM 3.
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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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12
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ITEM 4
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CONTROLS AND PROCEDURES
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13
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PART II – OTHER INFORMATION
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13
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ITEM 1.
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LEGAL PROCEEDINGS
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13
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ITEM 6.
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EXHIBITS
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13
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SIGNATURES
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14
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INDEX TO EXHIBITS
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CERTIFICATIONS
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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.
See attached financial statements on the following pages.
1
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
CONDENSED CONSOLIDATED BALANCE SHEETS
(In Thousands)
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September 30,
2012 |
December 31,
2011 |
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(unaudited)
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ASSETS
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Current assets:
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Cash and cash equivalents
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$ | 12,346 | $ | 14,238 | ||||
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Trade and other receivables
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5,442 | 6,602 | ||||||
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Net profits interests receivable - related party
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2,635 | 7,616 | ||||||
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Prepaid expenses
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12 | - | ||||||
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Total current assets
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20,435 | 28,456 | ||||||
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Other non-current assets
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19 | 19 | ||||||
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Total
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19 | 19 | ||||||
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Property and leasehold improvements - at cost:
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Oil and natural gas properties (full cost method)
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344,196 | 344,196 | ||||||
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Accumulated full cost depletion
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(242,817 | ) | (230,060 | ) | ||||
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Total
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101,379 | 114,136 | ||||||
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Leasehold improvements
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512 | 512 | ||||||
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Accumulated amortization
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(390 | ) | (354 | ) | ||||
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Total
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122 | 158 | ||||||
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Total assets
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$ | 121,955 | $ | 142,769 | ||||
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LIABILITIES AND PARTNERSHIP CAPITAL
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Current liabilities:
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Accounts payable and other current liabilities
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$ | 1,566 | $ | 529 | ||||
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Current portion of deferred rent incentive
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39 | 39 | ||||||
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Total current liabilities
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1,605 | 568 | ||||||
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Deferred rent incentive less current portion
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60 | 90 | ||||||
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Total liabilities
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1,665 | 658 | ||||||
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Commitments and contingencies (Note 2)
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Partnership capital:
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General partner
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3,613 | 4,242 | ||||||
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Unitholders
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116,677 | 137,869 | ||||||
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Total partnership capital
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120,290 | 142,111 | ||||||
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Total liabilities and partnership capital
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$ | 121,955 | $ | 142,769 | ||||
The accompanying condensed notes are an integral part of these condensed consolidated financial statements.
2
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
(In Thousands except Earnings per Unit)
(Unaudited)
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Three Months Ended
September 30, |
Nine Months Ended
September 30, |
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2012
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2011
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2012
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2011
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Operating revenues:
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Royalties
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$ | 11,567 | $ | 13,841 | $ | 35,929 | $ | 40,075 | ||||||||
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Net profits interests
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1,606 | 4,405 | 2,350 | 8,498 | ||||||||||||
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Lease bonus
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1,128 | 56 | 4,531 | 386 | ||||||||||||
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Other
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7 | 24 | 173 | 90 | ||||||||||||
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Total operating revenues
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14,308 | 18,326 | 42,983 | 49,049 | ||||||||||||
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Costs and expenses:
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Operating, including production taxes
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1,434 | 1,212 | 3,665 | 3,685 | ||||||||||||
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Depletion and amortization
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3,999 | 4,817 | 12,793 | 13,640 | ||||||||||||
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Impairment of full cost properties
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- | - | - | |||||||||||||
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General and administrative expenses
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745 | 828 | 2,429 | 2,745 | ||||||||||||
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Total costs and expenses
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6,178 | 6,857 | 18,887 | 20,070 | ||||||||||||
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Operating income
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8,130 | 11,469 | 24,096 | 28,979 | ||||||||||||
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Other (expense) income, net
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(1 | ) | 37 | 11 | 37 | |||||||||||
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Net earnings
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$ | 8,129 | $ | 11,506 | $ | 24,107 | $ | 29,016 | ||||||||
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Allocation of net earnings:
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General partner
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$ | 293 | $ | 367 | $ | 918 | $ | 986 | ||||||||
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Unitholders
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$ | 7,836 | $ | 11,139 | $ | 23,189 | $ | 28,030 | ||||||||
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Net earnings per common unit (basic and diluted)
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$ | 0.26 | $ | 0.36 | $ | 0.76 | $ | 0.91 | ||||||||
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Weighted average common units outstanding
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30,675 | 30,675 | 30,675 | 30,675 | ||||||||||||
The accompanying condensed notes are an integral part of these condensed consolidated financial statements.
3
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
(In Thousands)
(Unaudited)
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Nine Months Ended
September 30, |
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2012
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2011
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Net cash provided by operating activities
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$ | 44,036 | $ | 42,506 | ||||
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Cash flows used in investing activities:
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Adjustment related to acquisition of natural gas properties
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- | (6 | ) | |||||
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Cash flows used in financing activities:
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Distributions paid to general partner and unitholders
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(45,928 | ) | (38,014 | ) | ||||
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(Decrease) increase in cash and cash equivalents
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(1,892 | ) | 4,486 | |||||
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Cash and cash equivalents at beginning of period
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14,238 | 11,253 | ||||||
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Cash and cash equivalents at end of period
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$ | 12,346 | $ | 15,739 | ||||
The accompanying condensed notes are an integral part of these condensed consolidated financial statements.
4
DORCHESTER MINERALS, L.P.
(A Delaware Limited Partnership)
NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
1 Basis of Presentation: Dorchester Minerals, L.P. is a publicly traded Delaware limited partnership that was formed in December 2001, and commenced operations on January 31, 2003. The 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. All significant intercompany balances and transactions have been eliminated in consolidation.
The 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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” for additional information. Per-unit information is calculated by dividing the earnings or loss applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership has no potentially dilutive securities and, consequently, basic and dilutive earnings or loss per unit do not differ. These interim financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Partnership’s annual report on Form 10-K for the year ended December 31, 2011.
Fair Value of Financial Instruments — The carrying amount of cash and cash equivalents, trade receivables, payables, and other current liabilities approximates fair value because of the short maturity of those instruments. These estimated fair values may not be representative of actual values of the financial instruments that could have been realized as of quarter close or that will be realized in the future.
2 Contingencies: In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma regarding the use of natural gas from the wells in residences. The operating partnership now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a significant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact. On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership. On April 27, 2012, the parties successfully mediated terms for a settlement in the amount of $500,000 plus immaterial future royalty amounts on fuel gas. The settlement was approved by the District Court on October 18, 2012. A $500,000 reserve was recorded in Net Profits Revenues on the financial statements in the first quarter of 2012.
The Partnership and the operating partnership are involved in other legal and/or administrative proceedings arising in the ordinary course of their businesses, none of which have predictable outcomes and none of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.
5
3 Distributions to Holders of Common Units: Unitholder cash distributions per common unit since 2008 have been:
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Per Unit Amount
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2012
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2011
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2010
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2009
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2008
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First quarter
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$ | 0.541883 | $ | 0.426745 | $ | 0.449222 | $ | 0.401205 | $ | 0.572300 | ||||||||||
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Second quarter
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$ | 0.456351 | $ | 0.417027 | $ | 0.412207 | $ | 0.271354 | $ | 0.769206 | ||||||||||
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Third quarter
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$ | 0.343252 | $ | 0.455546 | $ | 0.471081 | $ | 0.286968 | $ | 0.948472 | ||||||||||
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Fourth quarter
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$ | 0.448553 | $ | 0.354074 | $ | 0.321540 | $ | 0.542081 | ||||||||||||
Distributions from first quarter of 2010 through the present were paid on 30,675,431 units; distributions from the second quarter of 2009 through the fourth quarter of 2009 were paid on 29,840,431 units; previous distributions above were paid on 28,240,431 units. The third quarter 2012 distribution was paid on November 1, 2012. 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 February 15, 2013.
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this 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.
We own six NPIs. The Minerals NPI (one of the six) owns certain cost bearing interests that were either in existence at the time of our formation, or created subsequent to our formation but associated with nonproducing mineral, royalty and leasehold interest properties acquired upon our formation. The Minerals NPI achieved a cumulative net profit status on September 30, 2011 as a result of its cumulative net revenue exceeding cumulative operating and actual and budgeted capital expenditures and development costs. Subsequent Minerals NPI amounts and payments distributed to us are:
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Distribution
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NPI Period Ended
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NPI
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Amount
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Period
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Nov. 30, 2011
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$ | 1,347,000 | $ | 1,306,000 |
4th Qtr. 2011
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Feb. 29, 2012
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$ | 709,000 | $ | 688,000 |
1st Qtr. 2012
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May 31, 2012
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$ | 354,000 | $ | 343,000 |
2nd Qtr. 2012
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Aug. 31, 2012
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$ | 395,000 | $ | 383,000 |
3rd Qtr. 2012
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6
Our consolidated financial statements reflect activity attributable to the Minerals NPI and include a portion of 2012 cash receipts and disbursements and accrued revenues and costs not yet received or paid. Prior to the Minerals NPI 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. Effective third quarter 2011, consolidated financial statements reflect activity attributable to the Minerals NPI, and will continue to do so regardless of its net profit status on a cumulative or reporting period basis.
Commodity Price Risks
Our profitability is affected by volatility in prevailing oil and natural gas prices. Oil and natural gas prices have been subject to significant volatility 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 economic conditions.
Results of Operations
Three and Nine Months Ended September 30, 2012 as compared to Three and Nine Months Ended September 30, 2011
Normally, our period-to-period changes in net earnings 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
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Nine Months Ended
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September 30,
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June 30,
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September 30,
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2012
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2011
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2012
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2012
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2011
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Accrual basis sales volumes:
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Royalty properties gas sales (mmcf)
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1,273 | 1,585 | 1,718 | 4,588 | 4,486 | |||||||||||||||
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Royalty properties oil sales (mbbls)
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88 | 86 | 92 | 267 | 245 | |||||||||||||||
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NPI gas sales (mmcf)
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1,067 | 990 | 1,068 | 3,253 | 2,553 | |||||||||||||||
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NPI oil sales (mbbls)
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20 | 14 | 16 | 51 | 18 | |||||||||||||||
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Accrual basis weighted average sales price:
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Royalty properties gas sales ($/mcf)
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$ | 3.02 | $ | 3.94 | $ | 2.10 | $ | 2.50 | $ | 3.95 | ||||||||||
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Royalty properties oil sales ($/bbl)
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$ | 88.39 | $ | 87.69 | $ | 87.69 | $ | 91.79 | $ | 91.17 | ||||||||||
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NPI gas sales ($/mcf)
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$ | 2.76 | $ | 4.10 | $ | 2.16 | $ | 2.42 | $ | 4.19 | ||||||||||
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NPI oil sales ($/bbl)
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$ | 86.54 | $ | 82.74 | $ | 80.88 | $ | 87.87 | $ | 84.68 | ||||||||||
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Accrual basis production and capital costs deducted under the NPIs ($/mcfe) (1)
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$ | 2.61 | $ | 0.93 | $ | 2.91 | $ | 2.84 | $ | 1.56 | ||||||||||
(1) Provided to assist in determination of revenues; applies only to NPI sales volumes and prices.
Oil sales volumes attributable to our Royalty Properties during the third quarter were up 2.3% from 86 mbbls during the third quarter of 2011 to 88 mbbls in the same period of 2012. Oil sales volumes attributable to our Royalty Properties during the first nine months were up 9.0% from 245 mbbls in 2011 to 267 mbbls in 2012. Oil sales volumes in both periods of 2012 have increased primarily due to activity in the Bakken and Rockies region. Natural gas sales volumes attributable to our Royalty Properties during the third quarter decreased 19.7% from 1,585 mmcf in 2011 to 1,273 mmcf in 2012. Natural gas sales volumes attributable to our Royalty Properties during the first nine months increased 2.3% from 4,486 mmcf in 2011 to 4,588 mmcf in 2012. The decrease in natural gas sales volumes in the third quarter of 2012 compared to the third quarter of 2011 is primarily due to natural declines and reduced activity in the Barnett Shale and the Fayetteville Shale. The increase in natural gas sales volumes in the first nine months of 2012 compared to the same period in 2011 is attributable to activity in the Barnett Shale.
7
Sales volumes and prices attributable to the Minerals NPI during periods prior to the third quarter of 2011 are excluded from the above table because DMLP did not receive any payments from such NPI sales volumes during those prior periods. Oil sales volumes attributable to our NPIs during the third quarter of 2012 were 20 mbbls, an increase of 42.9% from 14 mbbls during the same period of 2011. Oil sales volumes attributable to our NPIs during the first nine months increased 183.3% from 18 mbbls in 2011 to 51 mbbls in 2012. Natural gas sales volumes attributable to our NPIs during the third quarter of 2012 were 1,067 mmcf, an increase of 7.8% from 990 mmcf in the same period of 2011. Natural gas volumes attributable to our NPI’s during the first nine months increased 27.4% from 2,553 mmcf in 2011 to 3,253 in the same period of 2012, principally due to including the Minerals NPI. Minerals NPI oil sales volumes of 17 mbbls and 42 mbbls for the third quarter and first nine months of 2012, respectively, and gas sales volumes of 337 mmcf and 1,028 mmcf for the same periods, respectively, are included in the Net Profits Interest volumes above. During the third quarter and first nine months of 2011, Minerals NPI oil sales volumes were 11 mbbls and gas sales volumes were 203 mmcf. See “Overview” above.
The weighted average oil sales prices attributable to our interest in Royalty Properties were $87.69/bbl and $91.17/bbl during the third quarter of 2011 and first nine months of 2011, respectively, compared to $88.39/bbl and $91.79/bbl during the same periods of 2012, respectively. Third quarter weighted average natural gas sales prices from Royalty Properties decreased 23.4% from $3.94/mcf during 2011 to $3.02/mcf during 2012 and decreased 36.7% from $3.95/mcf during the first nine months of 2011 to $2.50/mcf during the same period of 2012. Both oil and natural gas price changes resulted from changing market conditions.
Third quarter weighted average oil sales prices from the NPIs increased 4.6% from $82.74/bbl in 2011 to $86.54/bbl in 2012 and increased 3.8% from $84.68/bbl during the first nine months of 2011 to $87.87/bbl during the same period of 2012. Third quarter weighted average natural gas sales prices attributable to the NPIs decreased 32.7% from $4.10/mcf during 2011 to $2.76/mcf in 2012 and decreased 42.2% from $4.19/mcf during the first nine months of 2011 to $2.42/mcf during the same period of 2012. Price changes during the three- and nine-month periods resulted from changing market conditions.
Our third quarter total operating revenues decreased 21.9% from $18,326,000 during 2011 to $14,308,000 during 2012, and our first nine months net operating revenues decreased 12.4% from $49,049,000 during 2011 to $42,983,000 during 2012 as a result of a first quarter 2012 Hugoton NPI litigation settlement reserve of $500,000, decreased natural gas production volumes on Royalty properties, and decreased natural gas prices. These amounts were partially offset by increased oil sales prices and increased oil and natural gas volumes in the Minerals NPI as discussed above.
Costs and expenses of $6,178,000 and $18,887,000 during the third quarter and first nine months of 2012, respectively, were down 9.9% and 5.9%, compared to $6,857,000 and $20,070,000 during the same periods of 2011. Increased ad valorem costs during the third quarter and first nine months of 2012 were offset by reduced production tax on reduced operating revenues. General and administrative costs were lower due to timing of expenditures in 2011 and non-recurring costs in 2011 as well as efficiencies gained.
Depletion and amortization costs were $3,999,000 and $12,793,000 during the third quarter and first nine months of 2012, down 17.0% and 6.2%, respectively, compared to $4,817,000 and $13,640,000 during the same periods of 2011. The effects of upward reserve revisions along with the inclusion of Minerals NPI reserves at 2011 year-end caused lower depletion rates per mcfe in 2012, which combined with sales volume changes in both the three and nine month periods.
Third quarter net earnings allocable to common units decreased 29.6% from $11,139,000 during 2011 to $7,836,000 during 2012 due to decreased natural gas sales prices and royalty gas sales volumes as discussed above, which was partially offset by increased lease bonus income. First nine months common unit net earnings decreased 17.3% from $28,030,000 during 2011 to $23,189,000 during 2012 due to decreased natural gas sales prices and the litigation reserve as discussed above, which was partially offset by increased oil and natural gas sales volumes and lease bonus income.
8
Net cash provided by operating activities decreased 22.5% from $14,892,000 during the third quarter of 2011 to $11,543,000 during the third quarter of 2012 due to decreased natural gas volumes and natural gas prices related to natural declines and reduced activity in the Barnett Shale and the Fayetteville Shale. The 3.6% increase from $42,506,000 during the first nine months of 2011 to $44,036,000 during the same period of 2012 is primarily due to increased oil and natural gas volumes and lease bonus income, partially offset by decreased natural gas prices.
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 2012 third quarter totaled approximately $10,300,000. These receipts generally reflect oil sales during June through August 2012 and natural gas sales during May through July 2012. The weighted average indicated prices for oil and natural gas sales during the 2012 third quarter attributable to the Royalty Properties were $83.94/bbl and $2.41/mcf, respectively.
Cash receipts attributable to our NPIs during the 2012 third quarter totaled approximately $833,000 and include Net Profits Interest payments from the Minerals NPI of approximately $383,000. These receipts reflect oil and natural gas sales from the properties underlying the NPIs generally during May through July 2012. The weighted average indicated prices received during the 2012 third quarter for oil and natural gas sales were $84.58/bbl and $2.35/mcf, respectively.
Cash receipts attributable to lease bonus and other income during the third quarter of 2012 totaled approximately $1.1 million. In total during the third quarter of 2012, there were 38 consummated leases and pooling elections located in 9 counties and parishes in three states.
We received division orders for, or otherwise identified, 136 new wells completed on our Royalty Properties and NPIs located in 16 counties and parishes in eight states during the third quarter of 2012. The operating partnership elected to participate during the third quarter of 2012 in seven wells to be drilled on our NPI properties located in six counties in four states.
Set forth below are summaries of recent activity on selected Royalty and NPI properties:
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. The New York State Department of Environmental Conservation has completed its regulatory review of high-volume hydraulic fracturing practices; however, development of these natural gas resources will be limited until remaining regulatory issues 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, NORTHERN 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 403 wells had been issued as of September 30, 2012, of which the operating partnership owns an interest in 234. In total, 381 wells were spud and 361 were completed as producers.
9
Set forth below is a summary of Fayetteville Shale activity through September 30, 2012 for wells in which we have a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI and wells for which we may not yet have received division orders or first payment.
|
2004
through
2008
|
2009
|
2010
|
Q1 2011 | Q2 2011 | Q3 2011 | Q4 2011 | Q1 2012 | Q2 2012 | Q3 2012 |
Total
to
Date
|
||||||||||||||||||||||||||||||||||
|
New Well Permits(1)
|
113 | 68 | 110 | 23 | 17 | 17 | 16 | 10 | 20 | 9 | 403 | |||||||||||||||||||||||||||||||||
|
Wells Spud
|
103 | 70 | 88 | 22 | 27 | 26 | 15 | 9 | 17 | 4 | 381 | |||||||||||||||||||||||||||||||||
|
Wells Completed(2)
|
81 | 49 | 88 | 29 | 18 | 17 | 33 | 20 | 9 | 17 | 361 | |||||||||||||||||||||||||||||||||
|
Royalty Wells in Pay Status (3)
|
36 | 55 | 70 | 22 | 19 | 16 | 10 | 22 | 29 | 12 | 291 | |||||||||||||||||||||||||||||||||
|
(1)
|
Excludes permits that expire undrilled.
|
|
(2)
|
Completion date is defined as the day the well commences production.
|
|
(3)
|
Wells in pay status means wells for which revenue was initially received during the indicated period.
|
Net cash receipts for the Royalty Properties attributable to interests in these lands totaled $515,000 in the third quarter of 2012 from 291 wells. Net cash receipts for the Minerals NPI Properties attributable to interests in these lands totaled approximately $336,000 in the third quarter of 2012 from 184 wells.
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. Operators active in this area include Continental Resources, EOG Resources, Hess Corporation, and Whiting Oil & Gas. Permits for 266 wells on these lands had been issued by the North Dakota Industrial Commission as of September 30, 2012, with 186 completed as producers. In most instances we elect to become a non-consenting mineral owner—who, according to North Dakota law, is not obligated to pay well costs, receives a royalty of 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 cashflow. 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, 2012, 16 of these wells had achieved 150% payout.
Market dynamics in the Bakken Trend have evolved resulting in higher lease bonus and royalty offers for unleased mineral interests. We are exploring our options and anticipate circulating a Request For Proposals (RFP) to industry participants seeking expressions of interest to acquire a lease on our interests in this area, to combine our interests with others or to pursue alternative transaction structures. We may engage the services of an investment bank or other agent to represent us with respect to a RFP or in a transaction. We can not project if, when or with whom we may elect to lease or otherwise transact all or any part of our interests as a result of this process.
Set forth below is a summary of Horizontal Bakken activity through September 30, 2012 for wells in which we own a royalty or Net Profits Interest. This includes wells subject to the Minerals NPI.
|
2004 through 2008
|
2009
|
2010
|
Q1 2011 | Q2 2011 | Q3 2011 | Q4 2011 | Q1 2012 | Q2 2012 | Q3 2012 |
Total
to
Date
|
||||||||||||||||||||||||||||||||||
|
New Well Permits
|
61 | 23 | 60 | 14 | 20 | 20 | 16 | 19 | 14 | 19 | 266 | |||||||||||||||||||||||||||||||||
|
Wells Spud
|
39 | 30 | 43 | 19 | 17 | 23 | 19 | 7 | 21 | 16 | 234 | |||||||||||||||||||||||||||||||||
|
Wells Completed
|
31 | 31 | 36 | 8 | 10 | 16 | 17 | 27 | 10 | 0 | 186 | |||||||||||||||||||||||||||||||||
|
Wells Reaching 150% Payout(1)
|
3 | 1 | 5 | 0 | 1 | 2 | 1 | 2 | 1 | 0 | 16 | |||||||||||||||||||||||||||||||||
|
(1)
|
Wells reaching 150% payout means wells for which the 150% penalty has been recovered during the indicated period.
|
10
Liquidity and Capital Resources
Capital Resources
Our primary sources of capital are our cash flow 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
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 anticipates gradual increases in expenses as repairs to these facilities become more frequent and anticipates gradual increases in field operating expenses as reservoir pressure declines. 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 $12,346,000 at September 30, 2012 and $14,238,000 at December 31, 2011.
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.
11
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 earnings. In addition to the impact on 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 volatile and 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.
12
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, 2012 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
In January 2002, some individuals and an association called Rural Residents for Natural Gas Rights sued Dorchester Hugoton, Ltd., along with several other operators in Texas County, Oklahoma regarding the use of natural gas from the wells in residences. The operating partnership now owns and operates the properties formerly owned by Dorchester Hugoton. These properties contribute a significant portion of the NPI amounts paid to us. On April 9, 2007, plaintiffs, for immaterial costs, dismissed with prejudice all claims against the operating partnership regarding such residential gas use. On October 4, 2004, the plaintiffs filed severed claims against the operating partnership regarding royalty underpayments, which the Texas County District Court subsequently dismissed with a grant of time to replead. On January 27, 2006, one of the original plaintiffs again sued the operating partnership for underpayment of royalty, seeking class action certification. On October 1, 2007, the Texas County District Court granted the operating partnership’s motion for summary judgment finding no royalty underpayments. Subsequently, the District Court denied the plaintiff’s motion for reconsideration, and the plaintiff filed an appeal. On March 31, 2010, the appeal decision reversed and remanded to the Texas County District Court to resolve material issues of fact. On June 30, 2011, the District Court issued a revised partial summary judgment in favor of the operating partnership. On April 27, 2012, the parties successfully mediated terms for a settlement in the amount of $500,000 plus immaterial future royalty amounts on fuel gas. The settlement was approved by the District Court on October 18, 2012. A $500,000 reserve was recorded in Net Profits Revenues on the financial statements in the first quarter of 2012.
The Partnership and the operating partnership are involved in other 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.
13
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: November 08, 2012
|
Chief Executive Officer
|
||
|
By:
|
/s/ H.C. Allen, Jr.
|
||
|
H.C. Allen, Jr.
|
|||
|
Date: November 8, 2012
|
Chief Financial Officer
|
||
14
|
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