Black Stone Minerals, L.P. quarterly report, Q2 FY2019

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Black Stone Minerals, L.P. — Q2 2019 Form 10-Q

Business context and reporting period

Black Stone Minerals owns oil and natural gas mineral and royalty interests across 41 states, as well as non-operated working interests. This unaudited filing covers the quarter and six months ended June 30, 2019; comparisons are to the corresponding 2018 periods. Amounts below are in U.S. dollars unless noted.

Financial and operating results

  • Q2 revenue: $163.6 million, up 49.7% from $109.3 million. The change primarily reflects a $29.2 million commodity-derivative gain versus a $33.3 million loss in Q2 2018. Revenue from customer contracts, excluding derivative results, declined 5.8% to $134.4 million.
  • Q2 earnings: Net income was $95.1 million versus $28.7 million; income attributable to the general partner and common and subordinated units was $89.8 million versus $23.5 million. Basic earnings per common unit were $0.45 versus $0.17.
  • Six-month results: Revenue was $247.4 million, up 10.6%; net income was $104.1 million versus $70.6 million. Common-unit basic earnings were $0.54 versus $0.40.
  • Production: Q2 production rose 16.7% to 4.748 million Boe (52.2 MBoe/day); first-half production increased 13.7% to 8.959 million Boe. Q2 realized prices excluding derivatives fell 13.8% for oil and 16.4% for natural gas; the six-month equivalent realized price declined 15.5% to $27.58/Boe.
  • Operating costs and margins: Q2 operating expenses were $63.0 million, down from $75.8 million, reflecting lower exploration and G&A costs. Operating income was $100.7 million versus $33.5 million. Calculated operating margin on reported total revenue was approximately 61.5% versus 30.7%; derivative gains and losses materially affect this comparison.
  • Cash flow: First-half operating cash flow was $201.0 million, up from $176.3 million. Investing used $46.0 million, compared with $91.3 million; financing used $156.5 million, compared with $83.6 million. Cash ended the period at $3.9 million.
  • Distributable cash flow: Management’s non-GAAP measure was $98.0 million for Q2 and $179.3 million for the first half, versus $87.2 million and $170.7 million, respectively, in 2018. Adjusted EBITDA was $108.3 million for Q2 and $203.3 million for the first half. These non-GAAP measures are not substitutes for GAAP results.
  • Debt and liquidity: Credit-facility borrowings were $436.0 million, up from $410.0 million at year-end; the weighted-average rate was 4.66%. The $675.0 million borrowing base left $239.0 million of available borrowing capacity. The $1.0 billion facility matures November 1, 2022. The Partnership reported compliance with its financial covenants.
  • Distributions: The Q2 distribution was $0.37 per common unit, approved July 25 and payable August 22, 2019. First-half distributions were $0.74 per unit. The Series B preferred units carry a 7% annual distribution.

Material changes versus the prior period

  • Higher production partly offset lower realized commodity prices and lower lease-bonus income. Q2 oil and condensate sales fell 4.1%; natural gas and NGL sales were nearly flat. First-half oil sales declined 12.3%, while natural gas and NGL sales rose 7.6%.
  • Derivative results were a major earnings driver: Q2 shifted from a loss to a gain; first-half derivative losses narrowed to $12.0 million from $49.7 million.
  • On May 24, 2019, all 96.3 million subordinated units converted one-for-one into common units after the subordination period ended. Common units are no longer entitled to arrearages.
  • First-half acquisitions of mineral and royalty interests totaled approximately $41.6 million, funded with cash and $0.9 million of common units. The Partnership also received farmout proceeds that reduced net investing cash use.

Outlook, commentary, risks, and unusual items

  • Shelby Trough activity: Management expects a temporary slowdown. XTO plans to complete previously drilled wells but pause new drilling until Q3 2020, citing gathering and treating capacity constraints. BPX limited activity to approximately 17,000 gross acres and released more than 100,000 gross acres; BSM intends to seek other operators for released acreage. In 2018, two operators in the area accounted for 21.4% of revenue and 36.7% of production.
  • Spending outlook: The 2019 development-capital budget for non-operated working interests is approximately $10.0 million, net of farmout reimbursements; $3.5 million had been invested in the first half. No formal full-year earnings or production guidance is provided in the supplied filing text.
  • Commodity exposure: BSM uses swaps and collars to reduce, but not eliminate, oil and gas price volatility. At June 30, it had hedged 91% of available 2019 oil volumes and 86% of available 2019 natural-gas volumes; derivatives are not designated as accounting hedges, so fair-value changes flow through revenue.
  • Other risks and contingencies: Results depend on commodity prices, production, operator drilling plans, transportation capacity, and operators’ access to capital. The filing identifies potential tax-law changes affecting publicly traded partnerships. Management said routine litigation was not expected to have a material adverse effect; no environmental remediation provision was recorded. A co-owner put option related to an acquired entity had not been exercised at June 30.
  • Accounting and farmouts: Adoption of lease accounting in 2019 resulted in operating lease assets and liabilities that management considered immaterial. Other long-term liabilities included $75.0 million of Pivotal farmout reimbursements associated with working interests already assigned.

Important facts for investors to verify

  • How much of reported earnings and cash generation reflects realized derivative settlements versus noncash fair-value movements.
  • Whether XTO’s planned pause, BPX’s acreage release, and replacement-operator plans alter Shelby Trough production or the asset’s contribution to cash flow.
  • Production trends and realized prices by commodity and basin, including the effect of lower natural-gas prices and lease-bonus variability.
  • Debt capacity, floating-rate exposure, covenant headroom, and the ability to fund distributions and acquisitions while maintaining liquidity.
  • The terms and potential dilution associated with Series B preferred-unit conversion beginning November 29, 2019, and the sustainability of common-unit distributions.