Black Stone Minerals, L.P. — Q2 2018 Form 10-Q
Reporting period: Three and six months ended June 30, 2018. Black Stone Minerals owns oil and natural gas mineral and royalty interests across 41 states and also holds non-operated working interests. Unless noted otherwise, dollar amounts below are in millions.
Financial performance and liquidity
| Metric | Q2 2018 | Q2 2017 | Six months 2018 | Six months 2017 |
|---|---|---|---|---|
| Total revenue | $109.3 | $120.5 | $223.8 | $245.1 |
| Income from operations | $33.5 | $57.8 | $81.5 | $122.9 |
| Net income | $28.7 | $54.2 | $70.6 | $115.8 |
| Net income attributable to common and subordinated units | $23.5 | $53.5 | $60.1 | $114.0 |
| Adjusted EBITDA | $100.3 | $74.7 | $195.3 | $152.6 |
| Distributable cash flow | $87.2 | $66.3 | $170.7 | $134.8 |
Q2 basic earnings per unit were $0.17 for common units and $0.06 for subordinated units, versus $0.33 and $0.22, respectively, in Q2 2017. Six-month amounts were $0.40 and $0.19, versus $0.69 and $0.49.
- Production: Q2 equivalent production rose 19.8% to 4.068 million Boe (44.7 MBoe/day). Oil and condensate volume increased 43.6%; natural gas volume rose 12.2%. Six-month equivalent production increased 19.4% to 7.881 million Boe.
- Realized prices: Q2 oil and condensate averaged $65.28/Bbl, up 44.4%; natural gas averaged $3.11/Mcf, down 4.0%. Six-month prices were $63.33/Bbl and $3.24/Mcf.
- Cash flow: Six-month operating cash flow was $176.3, up from $139.2. Investing used $91.3, including $56.1 for acquisitions, while financing used $83.6. Cash at June 30 was $7.1.
- Margins and costs: Q2 operating income was approximately 30.7% of total revenue, versus 48.0% a year earlier. Operating expenses rose to $75.8 from $62.7, including $6.7 of exploration expense for the PepperJack B#1 well.
- Debt and liquidity: Credit-facility borrowings were $421.0, up from $388.0 at year-end; the weighted-average rate was 4.6%. The borrowing base was $600.0, leaving $179.0 of available borrowing capacity. The partnership reported compliance with its covenants; it had $598.8 of total liabilities.
- Distributions: During Q2, declared and paid distributions were $0.3125 per common unit and $0.2087 per subordinated unit. In August, the board approved a Q2 distribution of $0.3375 per unit for both classes, payable August 23, 2018.
Changes versus prior year
Revenue from customer contracts increased 44.8% in Q2 and 36.5% for the first half, primarily reflecting higher production and oil prices. However, total revenue declined because derivative results swung from gains to losses: commodity derivative losses were $33.3 in Q2 2018 versus gains of $22.0 in Q2 2017, and losses were $49.7 for the first half versus gains of $44.7. Lower lease bonus income also weighed on first-half revenue. Net income fell despite higher Adjusted EBITDA and distributable cash flow, reflecting the substantial derivative valuation effects and preferred-unit distributions.
Higher production was mainly associated with the Midland/Delaware and Bakken/Three Forks areas for oil, and Haynesville/Bossier, Midland/Delaware, and Bakken/Three Forks for gas. Production taxes, G&A, DD&A, and interest expense increased; G&A growth included higher incentive compensation. The Series A preferred units were fully converted or redeemed by June 30; Series B preferred-unit distributions reduced earnings available to common and subordinated units.
Outlook, risks, and unusual items
- Management estimated a 2018 development-capital budget of $40–$45, of which $36.4 had been invested in the first half. It expected no further 2018 capital spending on the farmed-out Shelby Trough program and forecast $3–$8 of miscellaneous projects in the second half.
- Management said PepperJack A#1 appeared highly prospective and expected it to be completed as a commercially productive well; the B#1 step-out was unlikely to be completed in the near term. The $6.7 cost for B#1 was expensed. The partnership was negotiating with potential operating partners to develop the prospect.
- First-half 2018 acquisitions included Permian interests for $37.1 cash and East Texas unproved interests for $21.5 cash. A subsequent July acquisition was approximately $10.8, funded with cash and common units.
- The partnership’s outlook is exposed to oil and gas prices, production and operator activity, acquisition execution, transportation and service availability, regulation, and its ability to generate cash for distributions. Management cited EIA price forecasts of $67/Bbl WTI and $2.99/MMBtu Henry Hub for 2018, and $62/Bbl and $3.04/MMBtu for 2019; these are external forecasts, not company guidance.
- Derivatives are used to mitigate price volatility, not for speculation. At June 30, net derivative liabilities were $44.0. The company had hedged 88.0% of available 2018 oil volumes and 92.2% of available 2018 gas volumes; hedge coverage falls in later periods. Derivative fair-value changes flow through earnings and can materially distort reported revenue.
- Series B preferred units carry a 7% annual distribution and had a $298.4 carrying value. Cash or in-kind payment was permitted for the initial eight quarters; cash payment is required thereafter. The units become convertible beginning November 29, 2019, subject to stated terms.
- Environmental remediation provisions were not recorded because management did not consider potential costs significant. Noble Acquisition co-owners have repurchase options; none had been exercised by June 30 and no liability was recorded. Management considered ordinary-course litigation unlikely to have a material adverse effect. No material change to previously disclosed risk factors was reported.
Important facts for investors to verify
- Whether production growth and realized pricing can sustain operating cash flow as derivative settlements and fair-value changes vary.
- Current hedge positions, counterparties, and the effect of hedges on realized revenue and cash flow.
- Borrowing-base redeterminations, remaining credit availability, covenant headroom, and variable-rate interest exposure.
- Execution and commercial results at PepperJack, planned development spending, and the economics of recent and future acquisitions.
- Distribution coverage and the cash burden of common, subordinated, and Series B preferred distributions, including future preferred-unit conversion or payment terms.