Black Stone Minerals, L.P. — Q1 2019 Form 10-Q
Reporting period: Three months ended March 31, 2019; compared with Q1 2018. Black Stone Minerals owns mineral and royalty interests across 41 states and also holds non-operated working interests. Financial amounts below are in U.S. dollars; millions unless stated otherwise.
Financial and operating performance
- Revenue: $83.8 million, down 26.8% from $114.5 million. Revenue from customer contracts was $125.0 million, down 4.5%, but reported total revenue included a $41.2 million commodity-derivative loss versus a $16.3 million loss in Q1 2018.
- Production and realized prices: Equivalent production rose 10.4% to 46.8 MBoe/day. Oil and condensate volumes fell 6.9%, while natural gas volumes increased 18.3%. Realized prices excluding derivatives declined 15.1% for oil and condensate to $52.08/Bbl and 2.1% for natural gas to $3.31/Mcf.
- Profit: Operating income was $14.6 million, down from $48.0 million; net income was $9.0 million, down from $42.0 million. Income attributable to common and subordinated units was $3.8 million, versus $36.7 million. Basic earnings per common unit were $0.02, versus $0.23.
- Cash flow and non-GAAP measures: Operating cash flow was $90.2 million, up from $76.5 million. Investing used $24.4 million, versus $60.2 million. Financing used $67.0 million, versus $15.7 million. Adjusted EBITDA was $94.9 million, approximately unchanged from $95.0 million; distributable cash flow was $81.4 million, down from $83.4 million.
- Expenses: General and administrative expense rose 14.5% to $21.2 million, primarily due to higher incentive compensation. Lease operating expense increased 24.6% to $5.3 million; depreciation, depletion and amortization declined 2.6% to $27.8 million.
- Liquidity and debt: Cash was $4.2 million at March 31, versus $5.4 million at year-end. The revolving credit facility balance was $435.0 million, up from $410.0 million; unused availability was $240.0 million. The weighted-average borrowing rate was 4.75%. The Partnership reported compliance with its financial covenants.
- Distributions and equity: Common and subordinated unitholders received $0.37 per unit for the quarter, compared with $0.3125 and $0.2088, respectively, in Q1 2018. Series B preferred distributions were $5.25 million. The Board approved another $0.37 per common and subordinated unit, payable May 23, 2019; following payment, subordinated units were expected to convert one-for-one into common units.
Material changes and management commentary
- The revenue and earnings decline primarily reflected larger unrealized losses on oil derivatives, lower oil production and lower realized oil prices. Management also cited year-end receivable adjustments that reduced reported production by approximately 2.0 MBoe/day and Q1 revenue by approximately $6.2 million.
- Higher natural gas production, mainly from the Haynesville/Bossier play and Midland and Delaware Basins, partially offset the oil-related declines. Lease bonus and other income increased to $5.6 million.
- During Q1, the Partnership acquired mineral and royalty interests for approximately $20.0 million in cash and $0.9 million in common units. It expected 2019 development capital expenditures for non-operated working interests of approximately $10.0 million, net of farmout reimbursements; $2.4 million had been invested through March 31.
- Cash operating results included $1.7 million received on net derivative settlements, while the income statement reflected substantial derivative fair-value losses. Derivatives are not designated as accounting hedges, so fair-value changes affect reported revenue and income in the period.
Outlook, risks and contingencies
- The filing gives no company-specific earnings or production guidance. Management’s stated objective is long-term growth in reserves, production and operating cash flow, with quarterly distributions when practicable; distributions are not guaranteed.
- Management cited commodity-price volatility, production and reserve replacement, operator development and financing, acquisitions, transportation capacity, regulation, environmental requirements, and access to equipment and services as significant risks. Most production is natural gas, and the business depends on third-party operators’ drilling decisions.
- At March 31, 2019, the Partnership had hedged 92% of available 2019 oil and natural gas hedge volumes; the corresponding 2020 figures were 48% for oil and 38% for natural gas. Hedge positions can limit the benefit of higher prices as well as mitigate price declines. Derivative counterparties were rated Baa1 or better, but contracts are not collateralized.
- The credit facility is secured by substantially all oil and gas production and assets, carries floating rates, and matures November 1, 2022. A 1 percentage-point increase in the rate on the reported debt balance would have increased Q1 interest expense by approximately $1.1 million, assuming constant debt.
- The filing reported no material off-balance-sheet arrangements or material changes to previously disclosed risk factors. Management said routine litigation was not expected to have a material adverse effect; no liability was recorded for co-owner put options because none had been exercised. Potential environmental remediation costs were not considered significant and no provision was recorded.
- Management identified no material control changes and concluded disclosure controls were effective. Adoption of lease accounting resulted in immaterial right-of-use assets and liabilities and no reported income-statement impact.
Important facts for investors to verify
- How much of the derivative loss was unrealized, and how Q2–Q4 settlements and hedge positions affect realized cash flows.
- The extent to which the approximately $6.2 million year-end receivable adjustment is nonrecurring, and whether reported production trends persist.
- Credit-facility borrowing-base redeterminations, remaining availability, floating-rate exposure and covenant headroom.
- Whether distributable cash flow supports distributions after replacement capital needs, acquisitions and preferred-unit distributions.
- Completion and economic results of the PepperJack A#1 well; the filing said it was completed in April 2019 and evaluation was ongoing.
- The anticipated subordinated-unit conversion following the May 2019 distribution and its effect on the common-unit count and distribution priorities.