Dorchester Minerals, L.P. — 2012 Form 10-K Summary
Reporting period: Fiscal year ended December 31, 2012. The filing is an annual report, not a standalone fourth-quarter filing. Amounts below are in U.S. dollars; financial statement figures are in millions unless noted.
Business context
Dorchester is a publicly traded limited partnership that owns oil and natural gas royalty properties and net profits interests (NPIs). Its royalty interests span 574 counties and parishes in 25 states. The partnership generally does not operate or control development of its royalty properties. Quarterly distributions are based on available cash after expenses and reserves.
Financial performance and liquidity
| Metric | 2012 | 2011 | Change |
|---|---|---|---|
| Operating revenue | $63.204 million | $69.489 million | Down 9.0% |
| Net income | $38.022 million | $42.215 million | Down 9.9% |
| Net income per unit | $1.20 | $1.33 | Down 9.8% |
| Net cash from operating activities | $56.424 million | $55.496 million | Up 1.7% |
| Cash distributions paid to partners | $56.870 million | $52.505 million | Up 8.3% |
| Year-end cash | $13.792 million | $14.238 million | Down $0.446 million |
| Total liabilities | $0.537 million | $0.658 million | Down $0.121 million |
Operating income was $38.011 million; the operating margin was approximately 60.1%, compared with 60.7% in 2011. Depreciation, depletion and amortization was $16.583 million, down from $18.348 million. The partnership reported total assets of $123.800 million and partners’ capital of $123.263 million at year-end. It has no credit facility, does not anticipate borrowing, and its partnership agreement generally limits non-trade indebtedness to $50,000.
Revenue mix in 2012 included $49.237 million of royalties, $7.947 million of NPI income, $4.538 million of lease bonus revenue and $1.482 million of other operating revenue. The filing reports 2012 distributions of $1.790039 per unit in its capital statement; the fourth-quarter distribution was $0.433232 per unit, paid February 1, 2013. Distribution timing and the distinction between amounts paid during the fiscal year and distributions associated with production periods matter when comparing figures.
Material changes and operating trends
- Lower natural gas prices were the main reported reason for the annual revenue decline. Royalty-property gas price averaged $2.82 per mcf, down from $3.77; NPI gas price averaged $3.33 per mcf, down from $4.81.
- Oil prices eased modestly in 2012: royalty-property oil averaged $89.21 per barrel versus $91.55, and NPI oil averaged $87.67 versus $88.27. Royalty-property oil sales volume rose to 362 thousand barrels from 327 thousand; royalty-property gas sales volume declined to 6,007 mmcf from 6,212 mmcf.
- Lease bonus revenue rose sharply from $0.517 million in 2011 to $4.538 million, including approximately $2.807 million from two leasing transactions. Cash lease-bonus receipts were $4.568 million.
- Operating cash flow increased despite lower earnings, supported by lease bonuses and oil production and prices, partly offset by lower gas production and prices. Cash distributions paid to partners exceeded net income.
- Proved developed reserves at year-end were 3.647 million barrels of oil and 64,141 mmcf of gas. Oil reserves rose from 3.566 million barrels; gas reserves declined from 66,963 mmcf. The standardized measure of discounted future net cash flows fell to $211.694 million from $261.590 million, with the filing attributing the decrease principally to lower prices and production-cost changes, partly offset by reserve revisions and discount accretion.
Outlook, risks and unusual items
- Outlook: No specific financial or distribution guidance is provided. Management described 2012 results as strong despite low gas prices and reduced drilling activity in some areas. It said the operating partnership may pursue Oklahoma production improvements, depending on gas prices; costs and results are uncertain. Dorchester does not anticipate hedging commodity-price exposure.
- Commodity and operating exposure: Distributions depend heavily on volatile oil and gas prices, production, lease activity and operators’ development decisions. Royalty owners have limited access to operating information and little control over production. Producing reserves deplete, and replacement depends substantially on third-party drilling and acquisitions.
- NPI costs and concentration: NPI proceeds are reduced by eligible operating, development and other costs; deficits can carry forward and delay payments. A significant share of NPI properties is concentrated in the Hugoton field in Oklahoma and Kansas. Aging wells and gathering infrastructure may require repairs or upgrades.
- Regulation and environmental matters: Changing environmental, hydraulic-fracturing, emissions and other oil-and-gas rules may increase costs or constrain development. The filing also notes potential environmental liabilities and that the partnership does not carry business-interruption insurance.
- Governance and tax: The general partner controls the partnership, has conflicts of interest and receives allocated cash flows. Acquisition and issuance restrictions may limit growth; new unit issuance could dilute unitholders. Partnership tax allocations, depletion deductions and possible unrelated business taxable income involve uncertainty.
- Settlement: A royalty-underpayment lawsuit involving the operating partnership was settled for $500,000 plus immaterial future fuel-gas royalty amounts. A $500,000 reserve was recorded in first-quarter 2012, paid in December, and the case was dismissed.
- Accounting and audit: No impairment was recorded in 2012. Reserve estimates and accrued revenue and expenses rely on estimates; actual results may differ. The independent auditor issued unqualified opinions on the financial statements and internal control over financial reporting, which management also assessed as effective.
Important facts for investors to verify
- Confirm the causes and sustainability of the revenue and reserve-value declines, particularly lower natural gas prices and the impact of NPI costs.
- Reconcile reported annual distributions with the timing of quarterly receipts and the $0.433232 per-unit fourth-quarter distribution paid in February 2013.
- Review reserve-engineering reports, assumptions behind the standardized measure, and the continuing reserve contribution from the Bakken and other producing areas.
- Assess the concentration, condition and potential capital needs of Hugoton-area wells and gathering facilities, and any effect on NPI payments.
- Evaluate lease-bonus activity and the status and outcome of the proposed Bakken-area request for proposals; the filing does not predict whether or when a transaction will occur.
- Review the partnership’s limited debt capacity, cash reserves, distribution policy, general-partner reimbursements and partnership tax implications.