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As Wall Street discounts stacked pay by punishing high cost per acre, Eclipse Resources made an interesting play in January to lower their average per-acre costs that stirred investors. After announcing their acquisition of Travis Peak’s 44,500-net-acre, $93.7 million Flat Castle project in Northeast Pennsylvania, their stock dipped initially before jumping 20%. This $1,900-per-acre cost is less than the recent deals targeting the Utica in the Appalachian Basin. After their Jan. 30 analyst day, their stock took another prolonged dip. With the recent big swings in Eclipse’s market cap, looking into this latest acquisition finds there is more than meets the eye!

Deal Summary and Conclusions

  • Overall, there is a lot to like with this deal. Management was able to stay within the Appalachian Basin, which it knows well, and can implement their 16,000-foot laterals and aggressive proppant volumes. Although payback periods leave something to be desired, payback appears achievable if cashflows are managed correctly.
  • A $1,900 average cost per acre comes in much less than recent deals for core Utica acreage.
  • All equity-based purchase is a huge benefit, reducing cashflow risks associated with a cash-based purchase.
  • A projected to the 32 bcf wells stated on the investor relations reports.
  • In both the base case and upside case, extended payback periods were observed (around 9.1 and 7.7 years respectively), providing potential negative sentiment from shareholders regarding this acquisition.
  • The combination of an option to purchase Cardinal NE Holdings from Cardinal Midstream II for $18.3 million and the purchase being far west of northeastern Pennsylvania Marcellus production reduces midstream risk for the project. However, New York is directly to the north and has not allowed new pipelines to be built for some time, raising takeaway capacity concerns. Takeaway capacity will be a focus throughout this project’s life cycle.
  • The investor relations report states 87 drillable locations with a “wine rack” potential. The 87 locations seem reasonable assuming 1,200-foot spacing. With this stated, drilling all potential locations with their current rig program is questionable, especially if the wine rack style drilling is going to be implemented. This requires larger interval thicknesses.
  • Drilling longer laterals can lead to a reduced per-foot cost associated with drilling. However, higher upfront D&C costs lead to a longer breakeven times.
  • There is only one well producing from the Utica on this acreage (the Travis Peak drilled well), which creates a major concern with de-risking the expected EUR for new wells.
  • Economic incentives for drilling in this area include a low royalty burden of 17.7% on average and no current severance tax.
  • Statements by Eclipse that increased proppant volumes and lateral length will correlate with higher EURs appear to be warranted.

 

Map containing Point Pleasant Formation structure, active wells in the area colored by operator, leases colored by grantee, and the acquired acreage area.

Map containing Point Pleasant Formation structure, active wells in the area colored by operator, leases colored by grantee, and the acquired acreage area.

Investor Relations Report Completions and Drilling Analysis

  • Peak gas appears to positively correlate with horizontal length and total proppant in the area of interest.
  • Due to limited drilling in the Utica in this area, the entire Utica Shale play was analyzed. Lateral length and proppant totals appear to have a positive impact on peak gas.
Horizontal length vs peak gas in the Flat Castle project area and neighboring wells. Wells are colored by operator.

Horizontal length vs peak gas in the Flat Castle project area and neighboring wells. Wells are colored by operator.

 

Perforated interval length vs peak gas in the Utica/Point Pleasant. Wells are colored by first production date.

Perforated interval length vs peak gas in the Utica/Point Pleasant. Wells are colored by first production date.

Total proppant vs peak gas in the Flat Castle project area. Wells are colored by operator.

Total proppant vs peak gas in the Flat Castle project area. Wells are colored by operator.

 

Total proppant vs max initial production BOE in the Utica. Wells are colored by operator.

Total proppant vs max initial production BOE in the Utica. Wells are colored by operator.

Deal Analysis and Inputs

Inputs and assumptions for PDP and PUD calculations

Inputs and assumptions for PDP and PUD calculations

The rig schedule was calculated using DrillingInfo’s Rig Analytics tool. The days on-site for Eclipse wells with extreme lateral lengths (classified as over 15,500 feet) were filtered and days on-site were averaged out. To stay conservative, lower time-on-site extremes were filtered out. The average rig on-site time was determined to be 26 days. This value was then applied to a two-year drilling program, giving the program 28 wells total.
The drilling program was limited in this study to two years for several reasons. One is that new opportunities can occur in a basin rather quickly. It is difficult to project past two years into the future as drilling plans and company focuses change over time. In addition to this, we calculated drilling to begin in Q1 of 2019. This means we are forecasting three years in total. Forecasting beyond this seemed aggressive. If desired, further drilling can be forecasted using similar methods. Both scenarios assume one rig is mobilized to site.

Base Case Results

  • Uses wells in an expanded area of interest.
  • 25.8 bcf EUR is below IR reported 32 bcf, but is still solid.
  • 9.1 year payback period at 10% discount rate. The long time frame is due to the high D&C costs.
  • IRR of 26% and a PV10 of around $6,300,000.
  • 28 well drilling program.

Upside Case Results

  • Uses only the Travis Peak well on the acquired acreage.
  • 26 bcf EUR is below IR reported 32 bcf, but is still a strong projection.
  • 7.7 year payback period at 10% discount rate.
  • IRR of 30% and a PV10 of around $7 million.
  • 28 well drilling program.

 

Final Notice

  • Items to weigh: Long laterals account for an increase in peak rates, but proprietary cost per proppant and lateral drill costs are needed to assess fully return profiles.
  • Takeaway capacity to the north is an area of concern. New York lawmakers are making it increasingly difficult to pass any legislation allowing further pipeline construction. If the area is indeed proven up by future wells, more operators could move in and produce, which would further complicate takeaway capacity.
  • Sensitivity analysis regarding price was ran at $2.50 per mcf. At this rate, the project breakeven at a 10% discount wasn’t until year 10.
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Ian Thomasset