Dorchester Minerals, L.P. — Form 10-Q Summary
Reporting period: Three and nine months ended September 30, 2013. Financial statement amounts below are in millions of dollars unless noted. Dorchester owns oil and natural gas mineral, royalty, overriding royalty, leasehold and net profits interests across 574 counties and parishes in 25 states. Its six net profits interests (NPIs) generally receive 96.97% of net profits realized by the related operating partnership.
Financial performance and liquidity
| Metric | Q3 2013 | Q3 2012 | Nine months 2013 | Nine months 2012 |
|---|---|---|---|---|
| Operating revenue | $16.440 | $14.308 | $46.953 | $42.983 |
| Operating income | $10.718 | $8.130 | $30.250 | $24.096 |
| Net income | $10.749 | $8.129 | $30.422 | $24.107 |
| Net income allocated to common unitholders | $10.350 | $7.836 | $29.364 | $23.189 |
| Net income per common unit | $0.34 | $0.26 | $0.96 | $0.76 |
| Operating margin | 65.2% | 56.8% | 64.4% | 56.1% |
Q3 revenue increased 14.9% and nine-month revenue increased 9.2% year over year. Higher oil and gas prices and increased oil volumes contributed to growth; lower lease bonus income, lower gas volumes and higher costs on certain NPI properties partly offset it. Lower depletion and amortization helped reduce total costs and expenses.
- Cash flow: Operating cash flow was $14.830 million in Q3 2013 versus $11.543 million in Q3 2012; for the first nine months it was $42.508 million versus $44.036 million. Nine-month distributions paid were $40.535 million, compared with $45.928 million a year earlier.
- Balance sheet at September 30, 2013: Cash was $15.765 million; current assets were $27.171 million and current liabilities were $1.530 million. Total liabilities were $1.550 million and total assets were $114.700 million. The filing reports no debt; the partnership agreement generally bars indebtedness other than trade payables, subject to stated limits.
- Distributions: The Q3 2013 distribution was $0.455287 per common unit and was paid October 31, 2013. The partnership agreement required the next cash distribution to be paid by February 15, 2014.
Operating trends and material changes
For the first nine months, royalty-property gas sales volume fell 16.9% year over year, primarily from reservoir declines and reduced activity in the Fayetteville and Barnett Shales; royalty-property oil volume rose 5.6%. NPI gas volume fell 6.0%, while NPI oil volume rose 82.4%, largely reflecting activity in the Permian Basin and Bakken Trend. Average realized prices increased year over year for oil and gas on both royalty properties and NPIs.
Q3 royalty-property gas volume rose 4.2%, which management attributed primarily to a large release of suspended Fayetteville Shale production. Q3 royalty-property oil volume increased 18.2%; NPI oil volume increased 70.0%. Management cautioned that cash receipts may be affected by suspended funds and purchaser adjustments, and that indicated prices may not match contract prices.
General and administrative expense increased 12.1% in Q3 and 11.4% for the nine-month period, primarily due to non-recurring Bakken Trend costs. Depletion and amortization declined 11.3% and 20.3%, respectively, attributed to upward reserve revisions at year-end 2012 and lower 2013 gas volumes. The Minerals NPI and one minor NPI were in deficit status at September 30, 2013, primarily due to drilling activity; the partnership says NPI deficits are borne by the operating partnership, not the partnership.
Outlook, risks and contingencies
- No quantified earnings or production guidance is provided. Management said the operating partnership planned to continue efforts to increase Oklahoma production, potentially through fracture treatments, deepening, recompletions and drilling; costs and outcomes are uncertain and may affect NPI receipts.
- Management was evaluating potential transactions involving Bakken Trend mineral interests—including leasing, combining interests or other structures—and had engaged an investment bank. It gave no prediction whether, when or with whom a transaction might occur.
- Key exposures include volatile oil and natural gas prices, natural reservoir declines, drilling and capital costs underlying NPIs, regulatory uncertainty, and possible changes to reserve estimates. Reserve estimates affect depletion and the full-cost ceiling test; significant downward revisions could result in a non-cash impairment charge.
- The Rapp royalty class action was settled for $500,000 plus immaterial future fuel-gas royalty amounts; the settlement was paid in December 2012 and the case dismissed. Other ordinary-course legal or administrative proceedings were not considered likely to have a significant effect, though outcomes were not predictable.
- The partnership reported effective disclosure controls and no material changes in internal controls during the quarter. It does not anticipate hedging oil and gas price exposure.
Important facts for investors to verify
- Whether improved commodity prices and oil volumes can offset continuing gas-volume declines and changing lease bonus income.
- The scale and duration of drilling and other costs affecting NPI payments, including the status of NPIs currently in deficit.
- Progress, potential terms and any financial effect of the Bakken Trend transaction review.
- Reserve revisions and the full-cost ceiling-test outcome, as these could affect depletion or trigger impairment.
- Cash receipts, suspended production releases and purchaser adjustments relative to reported accrual-basis revenue and distributions.