Ring Energy, Inc. — Q3 2021 Form 10-Q
Business context and reporting period
Ring Energy is an independent oil and gas producer focused on properties in the Permian Basin of Texas and New Mexico. This unaudited quarterly report covers the three and nine months ended September 30, 2021; comparisons are with the corresponding 2020 periods.
Financial and operating performance
| Metric | Q3 2021 | Q3 2020 | Nine months 2021 | Nine months 2020 |
|---|---|---|---|---|
| Oil and gas revenue | $49.4 million | $31.5 million | $136.6 million | $81.7 million |
| Operating income (loss) | $24.4 million | $6.5 million | $63.9 million | ($140.3 million) |
| Net income (loss) | $14.2 million | ($2.0 million) | ($20.8 million) | ($93.2 million) |
| Operating cash flow | Not separately stated | Not separately stated | $49.5 million | $44.9 million |
- Q3 diluted earnings per share were $0.12; nine-month diluted loss per share was $0.21.
- Q3 production was 758,387 Boe, down from 878,480 Boe. Realized oil price rose to $69.61 per barrel from $38.80; natural gas price rose to $5.86 per Mcf from $1.96. Total realized revenue per Boe increased to $65.11 from $35.82.
- For the first nine months, production was 2.27 million Boe versus 2.36 million Boe. Total realized price per Boe rose to $60.26 from $34.59.
- Q3 lease operating expense was $7.0 million, down from $7.8 million, but increased to $9.21 per Boe from $8.90. General and administrative expense increased to $4.4 million from $2.5 million.
- Nine-month investing cash outflow was $33.9 million, including $35.3 million in development and property purchases, partly offset by $2.0 million of divestiture proceeds. Financing cash outflow was $17.2 million. Cash declined to $2.0 million from $3.6 million at year-end 2020.
- At September 30, debt under the revolving credit facility was $295 million, down from $313 million at December 31, 2020. The borrowing base was $350 million; the facility matures in April 2024. The company reported compliance with its covenants.
- Current assets were $25.3 million versus current liabilities of $85.2 million. Derivative liabilities totaled $44.5 million, including $38.4 million current. Stockholders’ equity was $275.6 million.
Material changes versus the prior comparable period
- Higher realized commodity prices drove revenue growth despite lower Q3 and year-to-date oil production. Q3 net income improved from a loss to a profit.
- Nine-month net loss narrowed substantially from 2020, which included a $147.9 million ceiling-test impairment. No ceiling-test impairment was recorded in 2021 through September.
- Nine-month results included a $73.6 million derivative loss, compared with a $32.9 million gain in 2020. Derivative settlements used $33.3 million of cash in 2021, versus $18.8 million received in 2020.
- Debt declined by $18 million during the first nine months. Common shares outstanding rose to 99.36 million from 85.57 million at year-end, primarily reflecting exercise of pre-funded warrants; 29.52 million common warrants remained outstanding.
Outlook, management commentary, and risks
- Management planned to complete 13 horizontal wells in 2021—10 on the Northwest Shelf and three on the Central Basin Platform; two had been drilled in 2020. Four wells were completed and placed on production in Q3, with limited contribution to that quarter but stronger contribution expected thereafter. The filing gives no specific 2021 capital-expenditure budget.
- Management emphasized disciplined capital allocation, cost control, free-cash-flow generation, and debt reduction, while continuing to pursue potential acquisitions. It expected production to improve following increased drilling investment.
- The February 2021 Texas winter storm shut in more than 60% of production and caused repair costs and higher year-to-date LOE per Boe. Management also described benefits from its conversion-to-rod-pump program.
- Commodity hedges reduced downside exposure but limited some upside. Q3 derivative results included an $8.2 million noncash fair-value gain and $14.9 million of cash settlements paid. The company said all hedged volumes were with lenders under its credit facility.
- Key risks include oil and gas price volatility, borrowing-base redeterminations, variable-rate debt, customer concentration, operational and weather risks, environmental regulation, and the potential need for additional capital. Three customers represented 90% of Q3 revenue; Phillips 66 alone represented 78%. The company reported no material changes to the risk factors in its 2020 Form 10-K.
- Management stated disclosure controls were effective. The filing reported no material subsequent events and no material change in internal control during Q3.
Important facts for investors to verify
- Whether the November 2021 borrowing-base redetermination changed borrowing availability or covenant headroom; the reported $350 million base is subject to redetermination and other adjustments.
- How much production and cash flow the newly completed wells contribute, and whether the 2021 drilling plan and spending remain within internally generated cash flow.
- The cash and earnings effects of the 2021–2022 oil hedges, including settlement payments, fair-value movements, and the remaining hedge volumes and prices.
- Liquidity and refinancing sensitivity given low cash, current liabilities exceeding current assets, $295 million of variable-rate debt, and the credit facility’s financial covenants.
- Potential dilution from the 29.52 million outstanding common warrants and the resulting share count if exercised.