Dorchester Minerals, L.P. — Q2 2013 Form 10-Q
Period: Three and six months ended June 30, 2013. Financial amounts below are in millions of dollars unless otherwise indicated. Dorchester owns producing and nonproducing mineral, royalty, overriding royalty, net profits, and leasehold interests across 574 counties and parishes in 25 states.
Financial performance
| Metric | Q2 2013 | Q2 2012 | First half 2013 | First half 2012 |
|---|---|---|---|---|
| Operating revenue | $17.295 | $15.242 | $30.513 | $28.675 |
| Operating income | $11.884 | $8.680 | $19.532 | $15.966 |
| Net income | $12.025 | $8.680 | $19.673 | $15.978 |
| Net income allocated to unitholders | $11.640 | $8.339 | $19.014 | $15.353 |
| Net income per common unit | $0.38 | $0.27 | $0.62 | $0.50 |
| Operating cash flow | $13.043 | $14.946 | $27.678 | $32.493 |
- Q2 revenue rose 13.5%; first-half revenue rose 6.4%. Unitholder income increased 39.6% and 23.8%, respectively.
- Costs and expenses were $5.411 million in Q2, down 17.5%, and $10.981 million for the first half, down 13.6%. Depletion and amortization declined 27.2% in Q2 and 24.3% for the first half; G&A increased 10.4% and 11.2%, respectively, partly due to nonrecurring Bakken Trend costs.
- For the first half, cash distributions paid were $27.958 million, versus operating cash flow of $27.678 million. Cash declined $0.280 million to $13.512 million.
Balance sheet and liquidity
- At June 30, cash was $13.512 million, current assets $25.549 million, total assets $116.625 million, and total liabilities $1.647 million. Partnership capital was $114.978 million.
- The filing reports no borrowings. Under the partnership agreement, indebtedness is generally limited to trade payables and may not exceed $50,000 in aggregate; the partnership says it does not anticipate a credit facility or debt.
- Cash and cash equivalents were $13.792 million at December 31, 2012. The partnership identifies NPI and royalty-property cash flows as its primary capital sources and says distributions are made after expenses are paid.
Changes, operating drivers, and outlook
- Higher oil and natural gas prices and increased NPI oil volumes supported revenue growth; lower natural gas volumes and lease bonus income partly offset the gains. Q2 lease bonus revenue fell to $35,000 from $3.127 million a year earlier. NPI revenue rose to $4.061 million from $318,000.
- Royalty-property gas volumes fell 29.8% in Q2 and 25.1% for the first half, primarily due to reservoir declines and reduced Fayetteville and Barnett Shale activity. NPI gas volumes declined 12.0% and 8.2%, respectively. NPI oil volumes increased, primarily due to Permian Basin and Bakken activity.
- Royalty-property gas prices averaged $3.84/mcf in Q2 versus $2.10/mcf; royalty-property oil prices averaged $93.84/bbl versus $87.69. NPI gas and oil prices also increased year over year in Q2.
- Management gave no quantified financial guidance. The operating partnership planned to continue Oklahoma production-enhancement efforts, depending on gas prices. The partnership was evaluating Bakken transactions—including leasing, combining interests, or other structures—and had engaged an investment bank, but could not predict whether or when a transaction would occur.
- The Q2 distribution was $0.395583 per unit and was paid August 1, 2013. The partnership agreement requires the next cash distribution to be paid by November 15, 2013.
Risks, contingencies, and notable items
- Results are exposed to oil and natural gas price volatility; the partnership does not anticipate hedging. Lower gas volumes, reservoir declines, operator activity, and market prices may affect receipts and NPI payments.
- Full-cost accounting and reserve estimates involve judgment. Downward reserve revisions or lower prices could cause a noncash impairment under the quarterly ceiling test and affect depletion expense.
- Development of the partnership’s Appalachian interests may be constrained by unresolved regulatory issues related to high-volume hydraulic fracturing. Potential Guymon-Hugoton infill drilling could require significant, unpredictable capital spending by the operating partnership and affect NPI receipts.
- A previously disclosed $500,000 royalty class settlement was paid in December 2012 and the case dismissed. Other ordinary-course legal or administrative matters were not believed to have a significant effect, though outcomes are not predictable.
- Management reported effective disclosure controls and no material changes in internal control over financial reporting during the quarter.
Important facts for investors to verify
- Whether stronger commodity prices can continue to offset declining natural gas volumes and lower lease bonus activity.
- Whether operating cash flow and cash balances can support distributions if distributions continue to exceed operating cash generation.
- Progress and potential terms of any Bakken leasing, sale, or other transaction, and the status of planned Oklahoma production activity.
- Updated reserve estimates, ceiling-test headroom, and any impairment or depletion impact in subsequent filings.
- The amount and timing of future distributions, which remain dependent on realized receipts, prices, volumes, and expenses.