Ring Energy, Inc. — Q2 2021 Form 10-Q
Business context and period. Ring Energy is an independent oil and gas producer focused on the Permian Basin in Texas and New Mexico. This unaudited quarterly report covers the three and six months ended June 30, 2021; balance-sheet comparisons are with December 31, 2020.
Key financial metrics
| Metric | Q2 2021 | Q2 2020 | Six months 2021 | Six months 2020 |
|---|---|---|---|---|
| Oil and gas revenue | $47.76 million | $10.64 million | $87.26 million | $50.21 million |
| Operating income (loss) | $23.24 million | $(156.85) million | $39.50 million | $(146.76) million |
| Net income (loss) | $(15.89) million | $(135.00) million | $(34.95) million | $(91.20) million |
| Net loss per share | $(0.16) | $(1.99) | $(0.35) | $(1.34) |
| Cash from operating activities | Not separately stated here | Not separately stated here | $32.01 million | $30.19 million |
Q2 operating margin was approximately 48.7%, calculated as operating income divided by revenue; the company nevertheless reported a net loss, primarily reflecting derivative losses. Q2 production was 792,551 Boe, with average realized prices of $65.00 per barrel of oil and $3.90 per Mcf of gas. Lease operating expense was $9.37 per Boe for the quarter; for the first half it was $10.37 per Boe.
At June 30, cash was $2.67 million, current assets $27.84 million, and current liabilities $87.88 million (a reported-balance-sheet current ratio of about 0.32). Revolver borrowings were $300.5 million against a $350 million borrowing base; the facility matures in April 2024 and is secured by substantially all company assets. The company reported compliance with its credit covenants. Total liabilities were $415.0 million and stockholders’ equity was $260.7 million.
Material changes versus comparable periods
- Q2 revenue increased $37.12 million year over year, reflecting higher realized oil and gas prices and higher sales volumes compared with the pandemic-related shut-ins in Q2 2020. Q2 oil volume rose to 702,408 barrels from 429,751 barrels; the realized oil price increased to $65.00 from $24.23 per barrel.
- The prior-year Q2 and first-half results included a $147.94 million noncash ceiling-test impairment. No such impairment was recorded in the first half of 2021.
- Derivative contracts generated a Q2 loss of $35.28 million and a first-half loss of $66.87 million. First-half cash settlements were a net $18.36 million paid, versus $17.09 million received in the 2020 period. Derivative liabilities totaled $52.67 million at June 30.
- First-half investing cash outflow was $21.22 million, including $22.72 million of development spending, partly offset by $2.00 million in property-sale proceeds. First-half financing cash outflow was $11.70 million; the company repaid $12.5 million net on its revolver.
- The company completed the exercise of remaining pre-funded warrants and some common warrants during the first half. Shares outstanding rose to 99.35 million from 85.57 million at year-end 2020; 29.52 million common warrants remained outstanding.
Outlook, management commentary, risks and unusual items
- Management expects to drill 11–13 and complete 13–15 horizontal wells in the Northwest Shelf and Central Basin Platform during 2021, above the original plan of 6–8 wells drilled and 8–10 completed. Planned 2021 capital expenditures were expected to be 90%–110% above 2020 levels. The filing provides no specific production, revenue or earnings guidance.
- Management said it aims to operate within internally generated cash flow, maximize free cash flow, reduce debt and pursue high-return development and acquisitions. It believes operating and derivative cash flows, cash on hand and borrowing capacity can fund operations and debt service.
- The February 2021 Texas winter storm shut in more than 60% of production and caused repair costs and downtime; management said most production restoration took more than two weeks. In Q2, three one-mile horizontal wells came online at the end of May.
- Hedges limit some exposure to falling prices but also constrain upside. Outstanding oil hedges included 2021 collars, puts and swaps, and 2022 swaps; derivative fair-value changes are recognized in earnings rather than hedge-accounted. All hedged volumes were with lenders under the credit facility.
- Key risks include volatile oil and gas prices, borrowing-base redetermination, liquidity and covenant compliance, production and drilling risks, customer concentration, weather, COVID-19 variants, environmental regulation and access to capital. Three customers represented 78%, 6% and 5% of first-half revenue. A 1% interest-rate change would affect annualized interest expense by approximately $3 million, based on period-end debt.
- The company recorded no federal income-tax benefit because it maintained a full valuation allowance against federal deferred tax assets; it recorded $190,644 of state deferred tax expense. It disclosed ordinary-course legal matters but no specific material proceeding. Management concluded disclosure controls were effective.
Important facts for investors to verify
- Confirm revolver availability after borrowing-base redetermination and review covenant calculations, since covenant-defined current assets and liabilities may differ from GAAP balance-sheet totals.
- Assess whether planned capital spending can be funded while reducing debt, given low cash balances, derivative settlement payments and the company’s reliance on operating cash flow and borrowing capacity.
- Review hedge volumes, strike prices, maturities and counterparty exposure alongside the substantial derivative liabilities and earnings volatility.
- Reconcile first-half oil sales volume: MD&A narrative reports 1,312,529 barrels, while the volume table reports 1,312,150 barrels.
- Evaluate customer concentration, the large warrant overhang, and the potential effect of commodity prices, operating costs and production outcomes on liquidity and returns.