Black Stone Minerals, L.P. annual report, FY2019

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Black Stone Minerals, L.P. — FY 2019 Form 10-K

Reporting period: Fiscal year ended December 31, 2019. The filing also reports fourth-quarter results; it is an annual report, not a standalone quarterly filing. Amounts are in U.S. dollars unless stated otherwise.

Business context

Black Stone Minerals owns and manages oil and natural gas mineral and royalty interests across 41 states, plus non-operated working interests. Its principal model is to lease mineral acreage and receive royalties, generally without bearing development costs. At year-end it reported approximately 16.8 million gross mineral acres, 69,045 mineral and royalty interest wells, and 9,717 gross non-operated working-interest wells.

Financial and operating performance

  • Revenue: $487.8 million in 2019, down 20.0% from $609.6 million. Oil and condensate sales were $263.7 million; natural gas and NGL sales were $199.3 million; lease bonus and other income was $29.8 million. Commodity derivatives produced a $5.0 million loss, versus a $14.8 million gain in 2018.
  • Profit: Net income was $214.4 million, down from $295.6 million. Income from operations was $235.2 million, compared with $318.4 million. Net income attributable to common and subordinated units was $193.4 million; basic earnings per common unit were $1.01 versus $1.46.
  • Margins: Operating income was approximately 48.2% of total revenue, versus 52.2% in 2018; net income margin was approximately 43.9%, versus 48.5%. These are simple calculations from reported figures.
  • Cash flow: Operating cash flow was $412.7 million, up from $385.4 million. Investing cash outflow was $48.6 million, compared with $163.8 million, reflecting lower acquisitions and investment spending, partly offset by farmout proceeds. Financing cash outflow was $361.4 million, including $325.4 million of distributions to common and preferred unitholders.
  • Non-GAAP cash measures: Adjusted EBITDA was $399.5 million, down from $419.4 million; distributable cash flow was $355.4 million, down from $368.2 million.
  • Production and costs: Production averaged 48.5 MBoe/d, up 4.8% from 46.3 MBoe/d. Natural gas production rose 8.4%, while oil and condensate volumes fell 3.7%. Realized oil price declined 11.7% to $55.20/Bbl and realized natural gas price declined 25.9% to $2.57/Mcf. Production costs and ad valorem taxes were $3.42/Boe, down from $3.81/Boe.
  • Liquidity and debt: Cash was $8.1 million and current assets were $102.3 million against current liabilities of $29.8 million. Credit-facility borrowings were $394.0 million, at a 4.05% weighted-average rate; $256.0 million of borrowing capacity remained under the $650 million borrowing base. The facility matures November 2022. The partnership reported compliance with its covenants at year-end.
  • Distributions: Common-unit distributions declared for 2019 totaled $1.48 per unit. The fourth-quarter distribution was $0.30 per common unit, paid February 24, 2020. Series B preferred units carry a 7% annual distribution with priority over common units.

Changes versus the prior comparable period

  • Lower realized commodity prices, weaker derivative results, and reduced lease bonus income drove the decline in revenue and earnings, despite higher total production.
  • Production mix shifted toward natural gas: Haynesville/Bossier growth helped lift gas volumes, while oil declines were concentrated in the Bakken/Three Forks and Eagle Ford.
  • Proved reserves fell to 68.5 million Boe from 69.9 million Boe. The standardized measure of discounted future net cash flows declined to $847.9 million from $1.09 billion, primarily reflecting lower prices and production-cost assumptions.
  • Debt declined by $16 million year over year. Acquisitions were $44.0 million in total consideration, versus $149.9 million in 2018; 2019 consideration included $0.9 million in common units.
  • The subordination period ended in May 2019, converting 96.3 million subordinated units into common units. Common-unit distributions rose from $1.33 in 2018 to $1.48 in 2019.

Outlook, commentary, risks, and unusual items

  • Management said drilling had slowed in the Shelby Trough, partly due to natural gas prices. XTO planned to postpone most drilling and completion activity until late 2020 or later; BPX had reduced development and released more than 100,000 gross acres. The partnership expected to seek replacement operators in 2020. In 2019, two Shelby Trough operators contributed 14% of royalty revenue and 58% of working-interest revenue.
  • The 2020 budget for non-operated working-interest capital expenditures was approximately $5 million, net of farmout reimbursements, mainly for workovers. Farmout arrangements had reimbursed $205.2 million cumulatively through year-end 2019; the company expected working-interest capital requirements to remain minimal in 2020.
  • Management cited then-current EIA forecasts of average 2020/2021 WTI prices of about $61/$68 per barrel and Henry Hub gas prices of about $2.21/$2.53 per MMBtu. These are forecasts cited in the filing, not company guidance.
  • In February 2020, two senior vice presidents departed and the partnership implemented workforce reductions and lower board and executive compensation. It expected a one-time cash severance charge of approximately $5 million in first-quarter 2020.
  • Commodity-price volatility, dependence on third-party operators, Shelby Trough concentration, reserve replacement, borrowing-base redeterminations, and environmental, hydraulic-fracturing, climate, and disposal-related regulation are material risks. A 10% reduction in SEC reserve pricing would reduce estimated proved reserve volumes by approximately 2%, according to management.
  • The filing reports no material off-balance-sheet arrangements and states that ordinary-course legal matters were not expected to materially affect financial condition or results. No proved-property impairment was recorded in 2019.

Important facts for investors to verify

  • Whether Shelby Trough activity resumes or replacement operators are secured, and the resulting effect on royalty and working-interest production.
  • Commodity-price and derivative exposure, including 2020 hedge coverage and settlement effects; the filing reported hedges covering 82.6% of available oil and 61.9% of available gas hedge volumes for 2020.
  • Liquidity headroom after the April 2020 borrowing-base redetermination, covenant capacity, and debt repayment requirements.
  • Reserve replacement and valuation assumptions: proved reserves declined, while the standardized measure was materially lower than in 2018.
  • Whether distributions remain supported by cash generation after preferred-unit distributions, debt service, capital needs, and the expected severance charge. Common distributions are discretionary and preferred units have priority.