Ring Energy's Third Quarter 2026 Earnings Conference Call - RING ENERGY INC

Financial Performance:

• Third-quarter revenue was $102.3 million, a 2% sequential decrease, driven by a 12% drop in realized oil prices; however, an overall realized price decline of only 6% to $53.91/BOE was mitigated by improved natural gas realizations (up from -$5.20 to -$0.30/MCF) and stronger NGL pricing ($10.38/bbl).
• Adjusted EBITDA rose 5% sequentially to $57.1 million, with an adjusted EBITDA margin improving to 56% from 52%.
• Adjusted cash flow from operations increased 7% to $50.4 million, while the quarter reported negative adjusted free cash flow due to deliberate acceleration of capital spending.
• Leverage ratio improved to 1.5x (down from 1.7x) based on total debt to trailing adjusted EBITDA; interest expense decreased to $7.7 million due to lower debt balances.
• Liquidity increased to approximately $236 million, and outstanding debt on the revolving credit facility stood at $350 million, down $10 million from the prior quarter and $70 million from the start of the year.
• Lease operating expenses (LOE) remained stable at $10.20/BOE, and total all-in cash operating costs declined to $21.03/BOE.
• Total sales volumes averaged 20,635 BOE/d (up 3% sequentially), with oil volumes at 12,818 bbl/d (up 1% sequentially).

Guidance and Future Outlook:

• Q4 2026 guidance (adjusted for divestitures): Oil volumes of 12,900–13,500 bbl/d; total volumes of 20,400–21,200 BOE/d; LOE of $9.80–$10.30/BOE; capital spending of $43–$48 million.
• Full-year 2027 guidance: Oil volumes of 13,200–14,300 bbl/d; total volumes of 21,000–23,000 BOE/d; preliminary capital range of $135–$165 million; LOE of $9.70–$10.50/BOE.
• 2027 capital plan includes 20–30 new horizontal wells with laterals exceeding 1.5 miles, targeting approximately 10% production growth on similar or slightly lower capital spending than previous years.
• Management expects a return to positive adjusted free cash flow in Q4 2026 and for the full year, driven by reduced capital spending in Q4 and higher commodity prices.
• Long-term leverage target is below 1.25x, with a strategic goal of reaching below 1.0x in 2027 if oil prices remain above $75/bbl to $80/bbl.

Business Segments and Product Lines:

• Completed $30.5 million in non-core asset sales, divesting ~130 BOE/d (63% oil) and ~9,800 net acres; $10 million used to reduce revolver debt, while $18.8 million was deployed to acquire leasehold interests offsetting the Central Basin Platform.
• Drilled eight horizontal wells and completed seven in Q3, including six two-mile co-developed laterals in Crane County (company's first 1.5-mile and 2-mile laterals) and two 1.5-mile laterals in Andrews County.
• Shifting development strategy toward multi-well pad drilling with longer laterals to enhance capital efficiency and production per foot.
• Expanded undeveloped inventory by acquiring acreage in the Central Basin Platform and Southern Northwest Shelf, focusing on stacked pay zones previously deemed uneconomic vertically.
• Completed a saltwater disposal well in Andrews County to support new development infrastructure.

Market and Competitive Landscape:

• Operating in the Permian Basin, benefiting from increased takeaway and processing capacity that improved natural gas basis realizations.
• Competition for the company's target acreage remains limited to private entities; no public companies were identified as direct competitors in the immediate leasing area.
• Leveraging higher commodity price environments and surplus proceeds to accelerate development ahead of production, contrasting with peers who may be more constrained by balance sheet leverage.
• The "higher for longer" price environment is viewed as a key catalyst to achieve leverage targets of below 1.0x.

Risks and Challenges:

• Production profiles may appear "lumpy" in the near term due to the shift to pad drilling and co-development, where wells are drilled and completed sequentially, potentially causing temporary offsetting production shut-ins to avoid frac interference.
• Full realization of capital efficiency gains and production growth benefits from the new 1.5–2 mile lateral program will take several quarters to reflect in financial results.
• Commodity price volatility remains a risk, though partially hedged; management is managing basis exposure, particularly for natural gas.
• Financial covenants require 25% hedging for months 13–24 until leverage drops below 1.25x and borrowing base drawdown is below 50%; this threshold is contingent on oil price levels.

Management Commentary and Tone:

• Management expressed high confidence in the transition to a capital-efficient, long-lateral development model, emphasizing that the company is "poised" to deliver durable per-share value.
• Tone was strategic and disciplined, framing negative free cash flow in Q3 as a deliberate investment to accelerate growth in 2027 rather than a financial weakness.
• CEO Paul McKinney highlighted that the company has been "catapulted" forward by two years regarding debt reduction and financial stability due to the strategic asset sales and timing of commodity price peaks.
• CFO Sanu Joel emphasized the resilience of the business model, noting that cost discipline allowed EBITDA growth despite a 6% drop in realized prices.

Analyst Questions and Answers:

• Jeff Robertson (Water Tower Research): Asked about capital efficiency metrics for 2027; Management confirmed that switching to 1.5–2 mile co-developed laterals should yield 10% growth on similar capital spend, though benefits will lag in financials due to the ramp-up time. Follow-up clarified that pad drilling may cause temporary production dips as offsetting wells are shut in during completion.
• Noel P. (Two Brothers): Inquired about the rationale for divestitures and acreage selection; Management explained they sold assets that did not compete for near-term capital to buyers who valued the deeper plays, using proceeds to expand their core, highly profitable Central Basin Platform footprint. Regarding geology, Management noted excellent oil-charged stacked pays across five horizontal targets in the Central Basin Platform, exceeding vertical economic thresholds via new technology.
• Follow-up on Hedging: Asked about hedge requirements tied to leverage; Management explained that current leverage (1.5x) still mandates 25% hedging for months 13–24; reducing leverage below 1.25x could lower this requirement, a move dependent on oil prices staying above $75–$80 to accelerate debt reduction.

Other Key Points:

• The company has proven up five horizontal targets in the Central Basin Platform, up from two targets previously, indicating significant inventory expansion.
• Management actively leases acreage and is concealing specific well performance data to avoid driving up competition prices for the target zones.
• The strategic shift involves acquiring acreage at attractive prices in areas previously considered uneconomic due to a lack of horizontal technology, now unlocking value via extended reach drilling.
• A borrowing base redetermination is scheduled for December, which will be an opportunity to discuss potential changes to covenants with lenders.