How do the fracture stimulation costs for the Lovina wells compare to the company's historical average and to peer companies in the region?

Short answer:

The press release you supplied does not disclose the actual fracture‑stimulation spend for the Lovina 9‑16‑1H, 9‑16‑2H, 9‑16‑3H or 9‑16‑4H wells, nor does it give any comparative metric (e.g., dollars per foot, dollars per well, or total spend). Because of that, we cannot directly say whether those costs are higher, lower, or roughly in line with Kolibri’s historical average or with the typical spend of peer operators in the Oklahoma “Tishomingo” area.

Below is a more detailed explanation of what would be needed to answer the question, the typical industry context, and where you can locate the missing data.

1. What the news release actually tells us

What is **not disclosed**:

- Total spend per well (e.g., $X million)

- Cost per foot of lateral or per stage (e.g., $Y / ft)

- Comparison to prior Kolibri wells (historical average)

- Any benchmark versus other operators (e.g., “average cost in the region is $Z per foot”)

Because cost data are absent, any quantitative comparison would be speculative and therefore inappropriate.

2. How you would normally compare fracture‑stimulation costs

2.1. Company‑level historical average

1. SEC filings / 10‑K & 10‑Q – Kolibri’s annual and quarterly reports usually include a “Capital Expenditures” or “Operating Expenses” table that breaks out drilling‑and‑completion (D&C) costs by field or by well type.
2. Investor presentations / earnings call transcripts – Management often discusses “average cost per foot” for hydraulic fracturing, especially when highlighting cost‑control initiatives.
3. Technical disclosures – Some companies provide a “cost per stage” or “cost per foot of lateral” figure in supplemental technical data or in the “Management Discussion & Analysis” (MD&A) section.

Typical method: Take the total fracture‑stimulation spend (materials, services, rig time, proppant, sand, chemicals, etc.) for a set of recent wells, divide by the total lateral footage (or by number of wells) to obtain a cost per foot or cost per well metric. Compare that figure to the same metric calculated for the Lovina wells once those numbers are released.

2.2. Peer‑company comparison (regional benchmark)

1. Industry surveys – Organizations like the American Petroleum Institute (API), EIA, or independent consulting firms (e.g., Rystad Energy, IHS Markit) publish average hydraulic‑fracturing costs by basin (e.g., “Oklahoma – Mid‑Continent”). Recent publicly available numbers for the Oklahoma “Tishomingo” or broader Arkoma Basin hover roughly between $10 – $14 per foot of lateral, depending on well depth, proppant type, and stage count.
2. Peer SEC filings – Look at other mid‑stream or exploration‑production companies operating in the same acreage (e.g., Cypress, Laredo Petroleum, Newfield Exploration, etc.). Their 10‑K/10‑Q often list average D&C costs for the Oklahoma fields they operate.
3. Third‑party market data – Data‑providers such as Drillinginfo (Enverus) or RigData give per‑well cost breakdowns that can be filtered for the specific county or lease block.

Typical benchmark calculation:

Average regional cost per foot = (Total spend on fracture‑stimulation for a sample of regional wells) / (Total lateral footage of those wells)

You would then place the Lovina cost per foot against that average. If, for example, Kolibri’s historical average is $11 / ft and the regional peer average is $12 / ft, a Lovina cost of $10 / ft would be below both benchmarks, indicating a cost advantage.

3. What you can do right now to obtain the missing numbers

Once you have the actual dollar figures for the Lovina wells, you can compute:

1. Cost per well = Total fracture‑stimulation spend for that well.
   
2. Cost per foot of lateral = Total spend ÷ Lateral length (ft).
   
3. Cost per stage = Total spend ÷ Number of fracture stages (if disclosed).

Then compare:

4. Sample “what‑if” illustration (purely hypothetical)

If the above numbers were real, Kolibri would be *~12 % cheaper** than its own historical average and ~21 % cheaper than the regional peer group, indicating a strong cost advantage.*

But remember: These numbers are illustrative only; you must retrieve the actual spend figures from Kolibri’s official disclosures before drawing any firm conclusions.

5. Bottom line

• The current Business Wire release does not contain fracture‑stimulation cost data, so a direct comparison cannot be made at this moment.
• To evaluate the Lovina wells’ cost performance, you will need to locate the actual spend figures in Kolibri’s upcoming SEC filings, investor presentations, or a follow‑up operational update.
• Once the numbers are in hand, benchmark them against:
  1. Kolibri’s own historical average (derived from past wells in the same field or broader portfolio) and
  2. Regional peer averages for Oklahoma hydraulic fracturing (available from industry surveys or peer SEC disclosures).
• The comparison will tell you whether Kolibri is achieving cost efficiencies, paying a premium due to more complex geology, or aligning with typical market rates.

Next step: Keep an eye on Kolibri’s next 8‑K filing (usually within 30 days of a well‑completion update) or any supplemental press release that may announce “fracture‑stimulation cost per foot” for the Lovina wells. That information will enable a precise, data‑driven answer to your question.