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Insights across the energy value chain

Cimarex Energy has recently agreed to sell some of its Delaware Basin assets to Callon Petroleum. This agreement includes 28,657 net acres predominantly in Ward County, Tx for $570 million. This deal sold at a relative discount to previous deals in the area when accounting for current production on acreage (Figure 1). This acquisition creates large plots of contiguous acreage for Callon to drill extended laterals while also providing Cimarex capital for it drilling projects in Ward, Reeves, Culbertson, and Eddy or to pay down debt.

Deal Summary and Conclusions

  • Callon appears to have acquired quality acreage at a discount relative to previous deals. The question now is whether they can optimize the acreage and quickly make the asset cashflow positive to reduce this newly added debt.
  • Cimarex was able to successfully divest acreage that was not competing for rig time and was not in its near-term plans. It can use this capital to pay off debt or finance its current rig program.
  • There seems to be a direct correlation with peak production and increased lateral lengths, but the key issue is finding contiguous acreage to maximize lateral length potential. This acquisition acreage intertwines with Callon’s current acreage position, which will greatly help facilitate the drilling of these extended laterals.
  • There appears to be some risk involved with Callon’s ability to drill up locations. Callon currently has 2 rigs in the area according to DI Rig Analytics. Although they appear to minimize their DUC inventory, they appear to lag in rig on-rig off time and well starts relative to their competitors in the area. Although their drilling history in the area is limited, they need to improve these drill times to see the upside displayed in this study.
  • According to investor relations reports in the PLS Database, a DrillingInfo company, Callon plans on targeting the Wolfcamp A and B. Although there is clear upside and proven production in the Bone Springs third carbonate, there is also clear upside in both Wolfcamp intervals. This is especially true when combining more aggressive completion and drilling practices.
  • Callon funded this acquisition through the offering of senior notes and common stock. Avoiding a pure cash transaction reduces the risk of cashflow issues, but at the expense of an increase in long term debt and dilution of common stock.
  • Breakeven in terms of recovering the $570 million investment will not occur with a 10% discount until year 5.4 assuming 10,000 ft laterals according to our base case. The highest risk appears to be Callon drilling behind schedule and not completing at a 2 well per month interval.
  • There is evident economic upside in extended lateral lengths and higher proppant loading.
  • According to 1Derrick, around 10,000 acres do not have rights down to the Wolfcamp. This is significant in that the Wolfcamp in the area gives around a 70-80% oil cut and is a zone of major upside which drive what they consider the highest netbacks of all operators in the area (they referenced they are getting $6-8 barrel more than regional average). An image of the area along with landtrac leases with depth clause call outs can be seen in Figure 2.
  • After initial concerns on Callon’s ability to successfully drill up acreage, Carrizo purchased acreage adjacent to it for a 30% premium. This further supports the thought the Callon purchased this acreage at a relative discount.
Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 1: Map from 1Derrick containing recent transactions in the Callon-Cimarex area. Values for $/acre account for current production on acreage.

 

Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 2: Plot of landtrac leases colored by depth clause availability. Note that this shows all leases in the area that expire in the next 10 years and not exclusively Callon and Cimarex aliased ones.

 

Geological Analysis

  • The acquired acreage lies on a thick zone of Wolfcamp A rock according to DI Play Assessments. This extra thickness opens up the potential for cube drilling/wine racking of wells.
  • It appears that this acreage falls in an oily zone in the Wolfcamp A. As seen in Figure 3, the Wolfcamp A wells that have oil assignments trend to the south and east with gassier wells to the northwest.
  • DI’s Wolfcamp A structural model shows this acreage falling in a structural low zone in the basin.
Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 3: Map showing an isopach map of the Wolfcamp A, the acquired acreage, and Wolfcamp A wells colored by production type.

Completions and Drilling Analysis

  • Peak BOE positively correlate with horizontal length. This trend is seen in all geological zones of interest. Callon Petroleum appears to agree with this correlation, as they plan on drilling 10,000 ft laterals according to their investor relations reports (1Derrick). It should be noted that Callon has not traditionally drilled to this lateral length.
  • The constraint in this area is typically not having contiguous acreage to drill at these lengths, however this acquisition certainly overcomes that issue.
  • Proppant intensity(proppant per foot) correlates strongly with peak rates. On average over the last 2 years, Callon seems to pump several hundred pounds more proppant per foot than Cimarex, revealing some upside in their completion tactics.

 

Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 4: Perforated interval vs peak BOE in AOI surrounding acquired acreage in several DI landing zones.

Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 5: Proppant per foot vs max initial production BOE in AOI surrounding acquired acreage in several DI landing zones.

Deal Analysis and Inputs

Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 6: Inputs and assumptions for PDP and PUD calculations.

The rig schedule was calculated using a combination of DrillingInfo’s Rig Analytics tool and the intel bytes tool from 1Derrick, a DrillingInfo company. These databases show that Cimarex has recently been drilling Wolfcamp wells at around 25 days per well. Callon runs 2 rigs in the area and takes a bit longer from a rig on to rig off standpoint but has a limited data sample. In this study, we will assume a drill schedule of 30 days per well. This schedule was projected out for 5 years, giving a total of 120 wells. This projection of 5 years is used as a cutoff point in these studies as it is difficult to project an operator’s capital allocation that far into the future.

This drill schedule was then used in conjunction with the average type curve of Wolfcamp A and Wolfcamp B wells for Callon Petroleum and Cimarex according to DI’s landing zones. All economics were run on a 10 percent discount rate. To better estimate the project economics of this asset under varying pricing conditions, 3 separate pricing scenarios were run. According to 1Derrick intel bytes, Callon plans to drill 10,000 ft laterals so the project type curve was normalized to 10,000 ft of horizontal length. This exercise assumes a start date of 8/1/2018. These economic projections are 240 months into the future.

Results Overview

Callon Petroleum-Cimarex Energy Deal Evaluation

Figure 7: Inputs and assumptions for PDP and PUD calculations for all three scenarios. Results for Base Scenario.

  • Uses horizontal Cimarex wells on the acreage for PDP.
  • Used Cimarex and Callon wells in the AOI that are horizonal, first producing after 1/1/2011, and assigned to the Wolfcamp A or B geology zones for PUD economics.
  • Assumes that 2 wells are drilled per month for 5 years.

Base Scenario

  • 1.86 bcf and 845,254 bbl EUR per well.
  • Projected EUR of 1,167,398 BOE (6:1) for new wells.
  • 65 month (5.4 year) payback period at 10% discount rate. In other words, the $570 million investment would be fully recuperated at a 10% discount rate at this time.
  • PDP and PUD values at a 10% discount were determined to be $372,269,180 and $837,658,359 respectively. This totals around $1,209,927,539 relative to the $570 million spent. Economics were projected out for 20 years.

Upside Scenario

  • 1.86 bcf and 845,254 bbl EUR per well.
  • Projected EUR of 1,167,398 BOE (6:1) for new wells.
  • 5 month (4.9 year) payback period at 10% discount rate.
  • PDP and PUD values at a 10% discount were determined to be $406,784,624 and $974,048,112 respectively. This totals to $1,380,832,736 relative to the $570 million spent. Economics were projected out for 20 years.

Downside Scenario

  • 1.86 bcf and 845,254 bbl EUR per well.
  • Projected EUR of 1,167,398 BOE (6:1) for new wells.
  • 6 month (6.3 year) payback period at 10% discount rate. In other words, the $570 million investment would be fully recuperated at a 10% discount rate at this time.
  • PDP and PUD values at a 10% discount were determined to be $337,377,833 and $697,331,722 respectively. This totals to $1,034,709,555 relative to the $570 million spent. Economics were projected out for 20 years.

Capital Sourcing

  • Utilizing PLS’s Capitalize searching tool, Callon appears to have made several capital raising and credit extending moves prior to this purchase. These offerings may be a potential capital source for funding this transaction.
  • May 31, 2018- Callon sold $400 million in 6.375% senior unsecured notes expiring in 2026.
  • May 25, 2018- Callon offered $261.1 million in new common shares, with JP. Morgan being the major underwriter.
  • April 5, 2018- Callon extended its credit facility to $650 million through 2023 to hedge against risk associated with senior notes.
  • $7.1 million in banking fees were paid through these transactions. Several institutions were listed on these transaction’s associated documents, but JP Morgan appeared to be the lead bookrunner.

Final Notes

  • Callon seems to have taken the long-term approach to this transaction while Cimarex is looking near to mid-term. Callon was able to successfully drastically increase its acreage in a core operating area that will allow it to extend laterals. It did so without offering up cash, which will allow for better cashflow near term. Callon, however, had to take on long term debt and common stock dilution in order to do so. Cimarex, on the other hand, was able to divest acreage that it was not focusing on and better improve its financial sheet and fund operations.
  • Items to weigh: Long laterals account for an increase in peak rates, but proprietary cost for proppant and lateral drilling costs are needed to assess fully return profiles. This is extremely significant as it appears to be one of the major ways Callon can add value to the acreage. Callon has also not historically drilled to these lengths, which brings into question their ability to optimize this technique to realize upside.
  • This analysis runs under the assumption of 2 completions per month. In order for Callon to capitalize on the acreage (assuming no divestiture down the road), it must improve on rig efficiencies.

 

 

 

 

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