Callon Petroleum-Cimarex Energy Deal Evaluation

Callon Petroleum-Cimarex Energy Deal Evaluation

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

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

 

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.

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

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.

 

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

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

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

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

Deal Analysis and Inputs

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

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

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

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.

 

 

 

 

WPX San Juan Deal

WPX San Juan Deal

WPX Energy made recent headlines with its announcement to sell its remaining San Juan Basin assets for $700 million.  This agreement includes 105,000 net acres in the oily Gallup play and comes at a cost of $6,667 per net acre.  Although WPX Energy did not disclose the buyer, regulatory filings stated the buyer was Enduring Resources.  This high oil concentration acreage sold at a premium to recent deals in the gassier northern portion of the basin.  WPX Energy recently sold its gassier acreage of 134,000 acres for a total cost of $169 million.  In mid-2017, Hilcorp purchased 1.3 million net acres from ConocoPhillips in the basin for a total of $2.5 billion cash, which equates to around $1,923 per net acre.  This divestiture will allow WPX Energy to focus time, rigs, and capital on its remaining core assets in the Williston and Permian Basins.

Deal Summary and Conclusions

  • Overall, this deal appears to be a mix of positives and negatives for both parties.
  • $6,667 per net acre appears to be a high price relative to the Hilcorp-Conoco deal, but this acreage falls in the higher oil concentrated area of the play.
  • The San Juan Basin has attractive drilling and completion costs relative to other major onshore unconventional basin (WPX was spending around $4.1 million in D&C costs per well). Enduring will need to keep similar contracts as WPX to maximize earning potential in the area.
  • There is a trend for WPX of better oil EURs in the northwestern portion of the acreage, which eludes to some potential risk for the southern acreage. Further drilling will be needed to see if this is a result of proppant loading and longer laterals or if its geology related.
  • This deal successfully allowed WPX to unload, what it considered, non-core assets in order to focus on their Delaware and Williston Basin assets. This deal also provides substantial capital to invest in future drilling programs in its core areas while also paying down debt.  Analysis conducted by 1Derrick, a DrillingInfo company, stated that “a significant portion of this $700 million will go to reducing debt, as WPX holds a debt-capital ratio of 38%”.  The selling price does appear to be below combined PDP and PUD calculations at a 10 percent discount, however. PUD and PDP were calculated to be $973,625,649 in total.
  • Enduring spent more money than previous deals in the area on this acreage, but PDP and PUD values at current market prices show upside in the acreage. Potential upside is also due to the acreage’s high oil cut relative to previous deals.
  • Enduring Resources’ previous iterations have bought, developed and sold acreage for a profit, similar to many private equity backed companies. Although this acreage has upside from a pure drilling standpoint, there are clear challenges in this “prove up and sell” model working in this area in the current market.  Upside will have to be proven through completion and drilling practices that show new and maximized value.  At a one rig deployed assumption, it will take 9 years to drill out this acreage.
  • Breakeven in terms of recovering the $700 million investment will not occur with a 10% discount until year 9.6 assuming 7250 ft laterals, which is the stated planned lateral lengths according to WPX IR reports. It is difficult to imagine a private equity backed E&P would be willing to wait this long for a significant return on investment let alone breakeven on their initial investment. This makes me believe the goal is to drill, prove up, and then sell.
  • There does appear to be some economic upside in extended lateral lengths.  Drill times in the Gallop field are fairly quick relative to other horizontal plays, so extending laterals should come in relatively cheap compared to other areas. This is due to the Gallup being a sandstone and having relatively shallow depths comparatively speaking. The ultimate question will be; what are cost increases associated with longer laterals going to be relative to increased initial production, and how far beyond current maximum lateral lengths will a positive initial production trend be seen (current perforated interval lengths max out around 9,500 ft)?

 

Figure 1: Map containing active horizontal WPX wells in the San Juan Basin involved in this sale sized by oil EUR and colored by first production date.

Figure 1: Map containing active horizontal WPX wells in the San Juan Basin involved in this sale sized by oil EUR and colored by first production date.

 

 

Figure 2: Acreage map of WPX sold acreage

Figure 2: Acreage map of WPX sold acreage

 

Completions and Drilling Analysis

  • As you can see in Figure 3, peak BOE appears to positively correlate with horizontal length. WPX Energy appears to have come to a similar conclusion, as they have been extending their lateral lengths over time which appears to have contributed to a 94% increase in peak BOE over the last 5 years.  Interestingly, they appear to have pulled back on some of the longer lateral wells in the last year, which leaves potential drilling upside for Enduring.  They plan on drilling an average of 7,250 ft laterals according to their investor relations reports.
  • Looking at Figure 4, proppant concertation (proppant per foot) does not seem to correlate strongly with peak rates.  Even if there is a loose upward correlation, it appears minor, and proppant costs may outweigh the value of added peak rates.  WPX appears to have tried to increase proppant loads in recent years, so there may be a cost cutting opportunity for Enduring. This might be due to the Gallop field being a sandstone which treats differently than a shale as in most resource plays. WPX did not appear to utilize specialty sands and used mostly 20/40 mesh sizing. If enduring can secure long term sand contracts or own their own mine they might be able to see reduced costs.
Figure 3: Perforated interval vs peak BOE in WPX wells in the San Juan Basin colored by first production date.

Figure 3: Perforated interval vs peak BOE in WPX wells in the San Juan Basin colored by first production date.

 

Figure 4: Proppant per foot vs max initial production BOE

Figure 4: Proppant per foot vs max initial production BOE

 

Deal Analysis and Inputs

Figure 5: Inputs and assumptions for PDP and PUD calculations

Figure 5: Inputs and assumptions for PDP and PUD calculations

The rig schedule was calculated using DrillingInfo’s Rig Analytics dataset.  The days onsite for WPX wells, with the projected lateral lengths were determined to be slightly below 10 days.  This drill time was then applied to a drill schedule until all drilling locations were drilled.  All economics were run on a 10 percent discount rate.  This exercise assumes a start date of 7/1/2018.  These economic projections are 240 months into the future.

Results

Figure 6: Economic inputs and results.

Figure 6: Economic inputs and results.

  • Uses WPX horizontal wells.
  • Assumes all 105,000 acres are drilled out using 320 acre spacing.
  • 2 bcf and 258,340 bbl EUR.
  • 6 year payback period at 10% discount rate. In other words, the $700 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 $411,354,991 and $562,270,658 respectively. This totals to $973,625,649 relative to the $700 million spent.  Economics were projected out for 20 years.
  • Projected EUR of 458,420 BOE (6:1) for new wells.

Final Notes

  • Although the total acreage PDP and PUD values are higher than the purchase price, it is difficult to imagine Enduring drilling out all locations over a 109 month time period. Typical private equity investments are liquidated in a 3 to 5 year timeframe, often shorter.  If the plan is to sell off assets in this timeframe, it appears there is a lot banking on drilling and completion tactics to increase acreage value and well return profiles.
  • 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 Enduring could add value to this acreage.
  • Although this is speculative, this may be a play that was bought on the assumption that oil prices are going higher for longer. The gamble may be to bet on higher prices in this 3-5 year timeframe with hopes that other operators get priced out of more competitive and densely populated basins and look elsewhere to operate.
  • Enduring will also assume WPX’s transportation commitments in addition to the Gallup assets.
Eclipse Resources Expands Its Position In The Appalachian Basin, What To Expect.

Eclipse Resources Expands Its Position In The Appalachian Basin, What To Expect.

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.