Black Stone Minerals, L.P. — 2015 Form 10-K
Reporting period: Fiscal year ended December 31, 2015. The Partnership completed its IPO in May 2015; annual results include predecessor operations before the IPO, so they are not fully comparable with post-IPO results. Unless noted, financial amounts are in U.S. dollars.
Business context
Black Stone owns oil and natural gas mineral and royalty interests across 41 states and 61 onshore basins, as well as non-operated working interests. At year-end, it reported approximately 14.6 million mineral-interest acres, 1.3 million NPRI acres and 1.4 million ORRI acres. Mineral and royalty interests are generally non-cost-bearing; working-interest participation requires the Partnership to fund its share of drilling and operating costs.
Financial and operating performance
| Metric | FY 2015 | FY 2014 |
|---|---|---|
| Total revenue | $392.9 million | $548.3 million |
| Net income (loss) | $(101.3) million | $169.2 million |
| Operating cash flow | $284.7 million | $396.1 million |
| Cash available for distribution and reinvestment, as defined by the Partnership | $233.7 million | $354.6 million |
| Year-end cash and cash equivalents | $13.2 million | $14.8 million |
| Year-end credit-facility borrowings | $66.0 million | $394.0 million |
| Total assets | $1,061.4 million | $1,326.8 million |
- FY 2015 production was 10.46 million Boe, or 28.7 MBoe/d, up 4.1% from 2014. Oil and condensate volumes rose 18.6% to 3.57 million barrels; natural gas volumes fell 2.1% to 41.39 Bcf.
- Realized oil and condensate prices declined 46.4% to $45.87/Bbl; realized natural gas and NGL prices declined 43.0% to $2.80/Mcf. These realized prices exclude derivative effects.
- Reported derivative gains were $90.3 million, versus $37.3 million in 2014. Lease bonus and other income fell 50.0% to $23.1 million.
- Property impairment charges rose to $249.6 million from $117.9 million, primarily reflecting lower expected commodity-price-driven cash flows. FY 2015 included $121.8 million of impairment on unproved properties.
- Lease operating expense was $2.06/Boe and production costs and ad valorem taxes were $3.42/Boe. General and administrative expense increased 23.0% to $77.2 million, reflecting IPO-related and incentive-compensation costs, among other items.
- Cash used in investing activities was $91.0 million; the Partnership reported $54.2 million of property additions and $62.3 million of acquisitions. Operating cash flow less reported investing cash use was approximately $193.7 million; this is a simple arithmetic comparison, not a company-reported free-cash-flow measure.
- At December 31, 2015, the borrowing base was $550 million and unused availability was reported as $484 million. The Partnership was in compliance with its debt covenants. Current assets were $103.6 million versus current liabilities of $63.0 million.
Fourth-quarter detail and material changes
- Fourth-quarter 2015 revenue was $100.0 million and net loss was $49.7 million, compared with third-quarter revenue of $137.0 million and net income of $53.9 million. Fourth-quarter loss attributable to common and subordinated units after the IPO was $51.3 million.
- For the full year, revenue declined 28.3% and operating cash flow declined 28.1% year over year. The filing attributes the revenue decline chiefly to lower commodity prices and reduced leasing activity, partly offset by higher derivative gains and oil production.
- Proved reserves ended the year at 49.8 million Boe, down from 51.1 million Boe. Proved developed reserves were 89.6% of the total; proved undeveloped reserves were 5.2 million Boe. The standardized measure of discounted future net cash flows fell to $555.0 million from $1.14 billion, substantially reflecting lower prices and production-cost assumptions.
- The IPO generated approximately $399.1 million of net proceeds in the cash flow statement; proceeds were used to repay substantially all then-outstanding credit-facility debt. The Partnership also purchased and cancelled 40,747 preferred units for approximately $41.5 million, leaving 77,216 preferred units outstanding at year-end.
Outlook, distributions and risks
- Management’s stated objective is long-term growth in reserves, production and operating cash generation, with distribution growth where practicable. The filing gives no numerical revenue or earnings guidance.
- The 2016 working-interest drilling budget was approximately $60 million, with about 95% allocated to Haynesville/Bossier and Bakken/Three Forks. Estimated 2016 development spending for year-end proved undeveloped reserves was $30.6 million.
- Including derivatives entered into after year-end, the Partnership reported hedging 91.7% of estimated 2016 oil and condensate production and 92.5% of estimated 2016 natural gas production from proved developed producing reserves; corresponding 2017 coverage was 44.2% and 46.5%.
- The board approved a fourth-quarter distribution of $0.2625 per common unit and $0.18375 per subordinated unit, paid February 26, 2016. The partnership agreement does not require distributions; preferred units have distribution priority while outstanding.
- On March 4, 2016, the board authorized a discretionary common-unit repurchase program of up to $50 million over six months, subject to liquidity, market conditions and other factors. No minimum repurchase amount is required.
- Key risks include depressed and volatile oil and gas prices, dependence on unaffiliated operators for drilling and production, reserve-estimate uncertainty, possible further impairments and borrowing-base reductions, and environmental, hydraulic-fracturing and other regulatory exposure. The credit facility restricts distributions in specified circumstances and requires total debt/EBITDAX of no more than 3.5:1 and a current ratio of at least 1.0:1.
- The filing reports no material off-balance-sheet arrangements and states that ordinary-course litigation was not expected to materially affect financial condition or results. The financial statements received an unqualified audit opinion; disclosure controls were judged effective, while management’s internal-control assessment and auditor attestation were omitted under the new-public-company transition rules.
Important facts for investors to verify
- How much of the reported $90.3 million derivative gain was realized cash versus unrealized mark-to-market gain, and how the hedge book affects future realized prices.
- The assumptions behind reserve estimates and the $555.0 million standardized measure, including the filing’s SEC reserve-price benchmarks of $50.28/Bbl oil and $2.59/MMBtu Henry Hub gas.
- Liquidity and covenant headroom at the next scheduled borrowing-base redetermination in April 2016, particularly if commodity prices remain weak.
- Whether operators maintain drilling activity sufficient to support production and convert proved undeveloped reserves, and whether planned 2016 working-interest spending remains economic.
- Distribution coverage and the preferred-unit priority, alongside the proposed $50 million repurchase authorization and its funding from cash or the revolving credit facility.