Black Stone Minerals, L.P. — Q3 2018 Form 10-Q
Reporting period: Three and nine months ended September 30, 2018. The partnership owns mineral and royalty interests across 41 states and 64 onshore basins, as well as non-operated working interests. Unless otherwise noted, amounts below are in millions of dollars.
Financial performance and liquidity
| Metric | Q3 2018 | Q3 2017 | Nine months 2018 | Nine months 2017 |
|---|---|---|---|---|
| Total revenue, including derivatives | $139.7 | $89.1 | $363.5 | $334.2 |
| Revenue from customer contracts | $158.2 | $98.5 | $431.7 | $298.8 |
| Operating income | $66.2 | $26.2 | $147.7 | $149.1 |
| Net income | $60.8 | $22.0 | $131.4 | $137.8 |
| Net income attributable to common and subordinated units | $55.5 | $21.4 | $115.6 | $135.4 |
| Adjusted EBITDA | $114.2 | $77.7 | $309.4 | $230.3 |
| Distributable cash flow | $100.8 | $69.1 | $271.5 | $203.9 |
Q3 production was 4.44 million Boe, up 30.4%; realized equivalent price was $32.81/Boe, up 29.4%. For the first nine months, production was 12.32 million Boe, up 23.2%, and realized equivalent price was $32.71/Boe, up 25.0%. The filing does not provide a clear company-reported margin measure.
Nine-month cash from operations was $289.7, compared with $211.7 in 2017; investing cash use was $143.7 and financing cash use was $147.2. Cash ended the period at $4.4. Capital expenditures and acquisitions were funded through operating cash, farmout proceeds, equity issuance, and revolving-credit borrowings.
At September 30, debt under the credit facility was $402.0, up from $388.0 at year-end 2017; weighted-average interest was 4.75%. The borrowing base was $600.0, leaving $198.0 available. Current assets of $117.1 compared with current liabilities of $114.7. The partnership reported compliance with its credit covenants. On October 31, the borrowing base increased to $675.0 and borrowing margins were reduced. The facility matures November 1, 2022.
Changes versus comparable periods
- Q3 revenue rose 56.8%, mainly from higher oil and gas volumes and realized prices. Q3 oil and condensate sales doubled; natural gas and NGL sales increased 40.0%.
- Q3 derivative losses widened to $18.5 from $9.3. For the nine months, derivative results swung to a $68.2 loss from a $35.4 gain, limiting overall revenue growth and contributing to lower nine-month net income.
- Nine-month oil and condensate sales increased 95.6% and gas/NGL sales increased 19.3%; lease bonus and other income declined 22.8%.
- Production costs and ad valorem taxes and G&A increased; nine-month exploration expense rose to $6.8, primarily from the PepperJack B#1 well. Interest expense increased with higher average borrowings and rates.
Outlook, management commentary and notable items
- Management estimated a 2018 development-capital budget of $45–$50; $45.7 had been invested through September. It expected no further net spending on the Shelby Trough working-interest program in 2018, and estimated $0.5–$0.7 of Q4 PepperJack A#1 completion costs plus $1–$2 for miscellaneous projects.
- On PepperJack, the partnership expensed $6.8 for the B#1 step-out well, which it did not expect to complete near term. It assigned 75% of its A#1 working interest to development partners, received $6.4 reimbursement for drilling costs and acreage, a $1.0 option payment, and retained an overriding royalty interest. Completion was expected in Q4, with BSM retaining a 25% non-operated working interest.
- Management’s stated objective is long-term growth in reserves, production, and operating cash flow while paying quarterly distributions when practicable. Distributions are not guaranteed and remain subject to available cash, preferred-unit distributions, reserves, and credit-agreement restrictions.
- The Board declared a $0.37 per common and subordinated unit distribution for Q3, payable November 21, 2018. On November 5 it authorized a discretionary $75.0 unit-repurchase program, which may be funded with cash or credit-facility borrowings.
- Series B preferred units carry a 7% annual distribution; quarterly distributions were $5.25 in Q3. Conversion into common units is available beginning November 29, 2019, subject to the stated terms. The former Series A preferred units were fully redeemed or converted by September 30.
- Commodity-price volatility is a key exposure. At September 30, derivative liabilities were $52.8 net of counterparty netting. Hedges covered 79% of available 2018 oil volumes and 83% of available 2018 gas volumes; coverage was 70% and 56%, respectively, for 2019. The partnership reported ten derivative counterparties, all rated Baa1 or better; nine were facility lenders.
- Other risks include operator-controlled drilling and production, commodity differentials and transportation, reserve replacement, acquisitions, and counterparty/customer credit. The filing reported no material change in risk factors, no material off-balance-sheet arrangements, no significant environmental remediation provision, and no litigation expected to have a material adverse effect. Management said disclosure controls were effective.
Important facts for investors to verify
- Whether production growth, realized prices, and acquisition contributions continue, and how much growth is attributable to the Noble acquisition and other asset purchases.
- The cash-flow effects of derivative settlements and fair-value changes, hedge coverage and prices, and the partnership’s exposure as contracts roll off.
- Available credit capacity after the October borrowing-base increase, floating-rate interest costs, covenant headroom, and debt funding for acquisitions, distributions, or repurchases.
- Whether distributable cash flow supports preferred and common-unit distributions after replacement capital needs; the measure is non-GAAP and uses estimated replacement capital expenditures.
- PepperJack A#1 completion results and costs, and the accounting, timing, and eventual release of farmout proceeds recorded as liabilities.
- Potential dilution from common-unit issuance and Series B conversion, alongside the terms and actual execution of the $75.0 repurchase authorization.