The Delaware Basin continues to be the leading basin in terms of deal flow with more than $15 billion in transactions YTD, which is 68 percent more than the next closest basin (Mid-Con/SCOOP and STACK). Resolute Energy could be the next major sell in the Delaware due to Kimmeridge Energy Management recently sending a letter to the Board of Directors of Resolute calling for them to swiftly begin a formal process to divest their Permian assets or merge the company with another Delaware Basin operator by the end of this year. Kimmeridge, who owns just less than 10 percent of the common shares of Resolute, believes that Resolute simply is not large enough to adequately develop their assets, and that an acquisition from a larger company is the best course of action. The following analysis was conducted using a variety of Drillinginfo products to derive an estimated proved reserves value, as well as identify potential candidates for an acquisition of Resolute’s Delaware Basin assets.
Summary and Conclusions
There are a decent number of offset operators to the Resolute acreage that would be ideal candidates for an acquisition of this size, and their past financial performance can be used as a guide for which candidate is most likely to consider the acquisition. Some of the top contenders include EOG, Conoco, Apache, and Energen (currently Diamondback).
- Resolute has a valuable acreage position in the Delaware Basin with ample existing production and significant upside that would be an ideal bolt-on acquisition for a variety of offset operators.
- The acreage lies on some of the highest producing areas of the Delaware for the Wolfcamp A and Wolfcamp B with oil cuts around 60 percent. There is some potential Bone Spring upside in the area as well.
- The company has made some significant efforts over the past few years to prove up reserves in the area by running two drilling rigs at the same time.
- Resolute has embraced the next generation of completion technology by adjusting up past the YTD Delaware average of 2,100 lbs. of proppant per lateral foot and 6,700 ft. laterals.
- These improvements in production have led to a sizeable proved reserves valuation that should satisfy the desires of Kimmeridge Energy. When comparing the PV10 of these reserves to other recent transactions in the area, valuation metrics indicate that the price of a transaction of this size could be as high as $1,500 MM.
According to Drillinginfo’s LandTrac leases and units, Resolute’s acreage position is centrally located in a high activity area of the Delaware Basin in the northern part of Reeves County (Figure 1). Using these DI LandTrac Leases, it is possible to determine if leases have any depth clauses mentioned in them that might diminish the value of the acreage (Figure 2). Of the 262 lease records that DI provides, there are 168 leases with depth clauses available, and 157 of those include Pugh clauses. The vast majority of these Pugh clauses mention the unit holding production down to 100 true vertical feet below the deepest producing formation, with some down to 300 feet below the deepest producing formation. Since most of Resolute’s wells are in the Wolfcamp A with a few going down to the Wolfcamp B, there should not be any leasing issues that materially affect the valuation of these assets. DI’s recently updated Basin Report on the Delaware Basin places this acreage in Tier 1 and Tier 2 EUR areas (Figure 3). Another asset for sale in the neighborhood is Felix Energy’s acreage in Loving, Winkler, and Ward counties. Although Felix has more net acreage than Resolute, their acreage is mostly in Tier 2 and Tier 3 EUR areas.
Figure 1 – Resolute’s acreage position according to DI LandTrac Leases and Units
Figure 2 – Map of Resolute’s acreage colored by depth clause type according to LandTrac Leases
Figure 3 – Tiered EUR map from the 2018 DI Delaware Basin report with Resolute and Felix acreage
DI Play Assessment maps show that the acreage lies on a relatively thick section of both the Wolcamp A and Wolfcamp B (Figures 4 and 5). Structurally, the basin gets deeper from west to east, so target depths within the acreage are going to vary. Resolute also claims to have upside potential in the Bone Spring Third Sand, but the company’s major focus has been on developing the Wolfcamp A and B.
Figure 4 – Wolfcamp A Thickness
Figure 5 – Wolfcamp B Thickness: The acreage lights up as the reservoir thickness of the Wolfcamp B section seems to be maxed out under Resolute, seen as upside drilling locations
Resolute has made haste on their drilling program during the commodity price downturn by spudding 35 wells from the beginning of 2015 to the end of 2017 (Figure 6). They say that this was mostly achieved through the implementation of pad drilling and batch completions, using two rigs while drilling three well pads in close proximity. However, there has been a noticeable decrease in new wells being spud by Resolute in 2018.
Figure 6 – Resolute wells spud by year
Resolute’s performance has been significantly improving year-over-year. Their average IP has more than tripled over the past five years while maintaining steady production decline (Figure 7). This is most likely being driven by increased proppant usage over the past few years which can be seen in Figure 8. As newer wells are being completed with higher amounts of proppant, initial production is increasing as well.
Figure 7 – Resolute type curve by year
Figure 8 – Resolute total proppant usage per well over time vs. first six months BOE production, colored by first production date
Improvements in initial production can also be attributed to the drilling of longer laterals. Figure 9 shows a positive correlation between increased lateral length and first six months of production in BOE. The bubbles are colored by DI Landing Zone and sized by total proppant.
Figure 9 – Resolute lateral lengths vs. first six months BOE production, colored by landing zone
Base Case Reserves Valuation
Using the 2017 Resolute 10-k and Intel Bytes from 1Derrick, an estimated number of remaining drilling locations was calculated. The August 2018 investor presentation for Resolute claims that the current spacing being used is 80 acres, so with net undeveloped acreage at 5,472 acres, the estimated number of remaining drilling locations is 68. For this analysis, the number of remaining locations was split evenly between the Wolfcamp A and B, so 34 wells per PUD scenario. Since Resolute is currently running two rigs, a well schedule was determined by assuming that two wells would be drilled every month, so one for each target landing zone. Average net revenue interest was assumed to be 80 percent for all cases. A flat oil price of $65/bbl and $3/Mcf for gas was used, and all NPV calculations were discounted at 10 percent. The following projections and economic outputs were calculated using DI WellCast.
Figure 10 – WellCast PDP reserves projection outputs
Figure 11 – Graph of gross PDP reserves projection. Current Daily BOE = 45,627 BOE/d
Figure 12 – PV10 economic projection output for Resolute’s PDP reserves
Figure 13 – Economic assumptions being used in the PDP and PUD models
Figure 14 – Wolfcamp A and B type curve outputs used in the PUD model
Figure 15 – PV10 economic projection output for Resolute’s PUD reserves
Figure 16 – PV10 economic projection output for Resolute’s total PDP and PUD reserves
Upside Case Reserves Valuation
Resolute’s August 2018 investor presentation also mentions significant upside potential by decreasing spacing assumptions in each target reservoir by infill drilling. This would result in twice as many drilling opportunities, meaning the PUD well count would jump from 68 to 136. This scenario was also modeled in DI WellCast, resulting in a $396 MM increase in present value to a PV10 of $1,579 MM (Figure 18).
Figure 17 – PV10 economic projection output for Resolute’s upside PUD reserves
Figure 18 – PV10 economic projection output for Resolute’s total upside PDP and PUD reserves
1Derrick M&A Metric Analysis
Figure 19 – Map of recent transactions near Resolute acreage
Figure 20 – 1Derrick deal metrics for recent comparable transactions in the area
Figure 20 was generated using the 1Derrick U.S. Deals M&A database, and it provides some meaningful metrics when evaluating a deal. Using these three recent transactions in the Delaware Basin, an average price per acre and price per BOE was calculated. Using the $12,981 price per acre value and Resolute’s 21,179 net acres (as stated in their 10-k), the estimated price for the acreage is about $274.9 MM. Then, taking the average price per BOE/d of $36,667 and multiplying it by Resolute’s average net daily production of 34,700 BOE/d, the estimated price for the PDP component of this potential transaction is about $1,272.3 MM. Using these metrics, the total purchase price for these assets could be as high as $1,547 MM. This is comparable to the DI WellCast upside case that resulted in $1,579 MM. Even though the PDP/PUD value split is different between the metric analysis and the reserves analysis, it is important to remember that each transaction is different, and these metrics should only be used as a reference tool for a valuation.
Figure 21 – Map of offset operators to Resolute’s acreage position that could be potential acquisition candidates
Figure 22 was created using the PLS Capitalize tool. Considering the metrics shown above, it appears EOG could be an ideal candidate for a bolt-on acquisition of this acreage. Their undrawn borrowing base and cash balance combined are more than $3 billion while their debt/EBITDA is the second lowest amongst this list of offset operators. However, sometimes debt/EBITDA ratios can be a misleading metric. For example, at the end of Q3 2018, Chesapeake had a debt/EBITDA ratio of 19.5 with a cash balance of about $4 MM but recently acquired WildHorse Resource Development in the Eagle Ford for just less than $4 billion.
Figure 22 – Potential acquisition candidates and their financial performance
When looking at Resolute’s well performance in the Wolfcamp A in relation to EOG’s offset performance to the north and south (Figure 23), Resolute has comparable calculated EUR for both oil and gas, proving that this acquisition would be very beneficial to EOG.
Figure 23 – Wolfcamp A type curve for EOG compared to Resolute
Natural gas storage inventories increased 39 Bcf for the week ending November 9, according to the EIA’s weekly report. This week’s injection is slightly above market expectations, which were 36 Bcf. Sticking with the trend over the past couple of weeks, this week’s build comes from the Midwest and the South Central, which accounted for 36 Bcf of the 39 Bcf injection.
At the time of writing, the December 2018 contract was trading at $4.140/MMBtu, ~$0.697/MMBtu below the December 2018 close of $4.837 yesterday.
Working gas storage inventories now sit at 3.247 Tcf, which is 528 Bcf below last year and 601 Bcf below the five-year average.
The December 2018 contract has traded in a wide range in November, from $3.237/MMBtu to $4.837/MMBtu. Prices soared again this week, with the December 2018 contract closing at the November high of $4.837/MMBtu yesterday; the December ‘18 contract has a closing average $4.24/MMBtu so far this week. The price volatility for December can be explained somewhat by the fundamentals—weather, storage levels, production, and demand—but there is also some thought that the financial markets are playing a role that caused the December contract to reach the highs yesterday. The thought is that hedge funds were long crude and short natural gas for the winter, which have historically been profitable. However, with gas trending up and crude trending down, these hedge funds were forced to unwind their positions to avoid any further loss.
See the chart below for projections of the end-of-season storage inventories as of November 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending November 15, 2018.
- Dry gas production decreased 0.40 Bcf/d on the week. Production decreases in the Mountain Region (-0.30 Bcf/d) and the South Central Region (-0.18 Bcf/d) are the main contributors to the drop in production. Within the Mountain Region, a majority of the movement came from New Mexico (-0.24 Bcf/d). Texas (-0.37 Bcf/d), Louisiana (+0.12 Bcf/d), and the GoM (+0.11 Bcf/d) are the main drivers of the South Central Region change.
- Canadian imports increased 0.72 Bcf/d for the week. Roughly 0.41 Bcf/d of the Canadian import increase comes from additional receipts on Iroquois flowing into New York.
- Domestic natural gas demand increased 21.63 Bcf/d week over week. The cold weather caused heating demand to increase, causing Res/Com to increase 16.44 Bcf/d. Power and industrial demand also increased 3.74 Bcf/d and 1.46 Bcf/d, respectively.
- LNG exports increased 0.45 Bcf/d week over week, while Mexican exports decreased by 0.17 Bcf/d.
Total supply is up 0.32 Bcf/d, and total demand is up 22.53 Bcf/d week over week. With the increase in demand outpacing the increase in supply, the EIA is expected to report the first draw of the season. The ICE Financial Weekly Index report is currently expecting a draw of 118 Bcf for next week. Last year for the same week was a draw of 46 Bcf, while the five-year average is a draw of 49 Bcf.
US crude oil stocks posted a large increase of 10.3 MMBbl last week. Gasoline and distillate inventories decreased 1.4 MMBbl and 3.6 MMBbl, respectively. Yesterday afternoon, API reported a large crude oil build of 8.8 MMBbl, while reporting a gasoline build of 0.18 MMBbl and a distillate draw of 3.2 MMBbl. Analysts were expecting a smaller crude oil build of 3.0 MMBbl. The most important number to keep an eye on, total petroleum inventory levels, posted a decrease of 1.4 MMBbl. For a summary of the crude oil and petroleum product stock movements, see the table below.
US crude oil production increased 100 MBbl/d last week, per EIA. Crude oil imports were down 87 MBbl/d last week, to an average of 7.5 MMBbl/d. Refinery inputs averaged 16.4 MMBbl/d (24 MBbl/d more than last week), leading to a utilization rate of 90.1%. The reaction to the report has been mixed as significant crude oil build is pressuring prices, while the decline in total petroleum stocks and news regarding OPEC and Russia potentially introducing supply cuts in 2019 are giving support to prices. Prompt-month WTI was trading up $0.66/Bbl, at $56.91/Bbl at the time of writing.
Prices extended their losses and sank on Tuesday dipping below the $56/Bbl mark to their lowest year-to-date. WTI prices have now fallen for 12 consecutive sessions. This is the longest losing streak for WTI since it started being traded on the New York Stock Exchange. Both benchmarks have fallen more than 20 percent since hitting their four-year highs in early October. The WTI market has now shifted its sentiment to bearish, flipping from being a speculator-driven bull market due to anticipation of a supply shortage from Iranian sanctions to being a fundamentally oversupplied market due to rapidly rising supply levels and a weaker demand growth.
The announcement of Iranian sanctions gave no support to prices; to the contrary, it drove them down due to the temporary waivers granted to eight countries (China, India, Japan, Italy, Greece, Turkey, South Korea, and Taiwan). This decision by the US government caused a shift in sentiment, as OPEC and Russia had agreed in June to produce more crude in order to offset the anticipated declines by Iranian sanctions. OPEC (led by Saudi Arabia) and Russia have increased production to historical levels since then. US production has also increased to historical highs, which is also contributing to the supply surplus. The rising supply levels from OPEC, Russia, and the US, as well as a weaker demand outlook, now have the market convinced that a supply glut will materialize moving into 2019.
Although OPEC and Russia had agreed to increase output, the recent price crash caused them to backtrack and possibly reverse their decision in 2019. On Sunday, OPEC and Russia signaled a potential joint production cut in order to prevent a global supply glut. However, a decision was not made, as Russia’s energy minister, Alexander Novak, said it was too early to make a decision to reverse course. OPEC will be re-grouping in Vienna on December 6 to discuss and determine its next move in terms of potential supply cuts.
Although news about OPEC potentially reducing supply levels was a bullish headline, it had no effect on prices, instead prices saw further declines following a tweet from President Donald Trump urging Saudi Arabia and OPEC to stay the course and continue producing to keep the oil prices down Another factor that pressured prices despite the bullish OPEC headline was OPEC projecting significantly less demand growth in 2019, just like IEA has projected, which led prices down to their lowest level of the year.
New selling from the speculative shorts and an increase in producer selling have pressured prices into extremely over-sold levels. Prices already dipped below the lows of 2018, falling below $56/Bbl. This type of selling usually abates with prices likely to bounce off the lows and retrace some of last week’s declines. The highs of last week at $64.14/Bbl are the first target, while the respected 200-day average of $67.36/Bbl will be challenged next. Prices will continue to be under pressure with the current global supply levels and a weaker demand growth. The bullish headlines, such as OPEC supply cuts or anything relating to Iranian production declines, will give support to prices. Regardless of any bounce, the market has lost a significant amount of its bullish bias. Drillinginfo continues to believe the long-term range will occur between $60/Bbl and $65/Bbl for an extended period of time, with the short-term range being between $55/Bbl and $60/Bbl as market waits to hear news from the next OPEC meeting.
Petroleum Stocks Chart
Natural gas storage inventories increased 65 Bcf for the week ending Nov. 2, according to the EIA’s weekly report. This week’s injection is above market expectations, which were 59 Bcf. The majority of this week’s build again comes from the Midwest and the South Central, which accounted for 54 Bcf of the 65 Bcf injection.
At the time of writing, the December 2018 contract was trading at $3.532/MMBtu, slightly below the December ‘18 close yesterday of $3.555.
Working gas storage inventories now sit at 3.208 Tcf, which is 580 Bcf below last year and 621 Bcf below the 5-year average.
So far during November, the December ’18 contract has traded in a range of $3.237/MMBtu and $3.567/MMBtu. Prices soared this week, with the December ’18 contract closing at the November high of $3.567/MMBtu on Monday, a jump of ~$0.28/MMBtu from the close on Nov. 2. The drastic increase in prices resulted from the past weekend’s change in the weather forecast, where the temperature outlook changed from mild to cold across the Midwest and Northeast. The weather forecast change has produced what is expected to be the first draw of the season for the week ending Nov. 16, currently expected to be 72 Bcf, according to the ICE Financial Weekly Index report.
See the chart below for projections of the end-of-season storage inventories as of Nov. 1, the end of the injection season.
This Week in Fundamentals
The summary below is based on Bloomberg’s flow data and DI analysis for the week ending Nov. 8, 2018
- Dry gas production decreased 0.62 Bcf/d on the week. A majority of the decrease can be attributed to production decreases in the South Central Region (-0.33 Bcf/d), mainly Louisiana (-0.29 Bcf/d). Other contributors to the decrease were the Mountain Region (-0.16 Bcf/d) and the Northeast (-0.14 Bcf/d).
- Canadian Imports decreased 0.15 Bcf/d for the week.
- Domestic natural gas demand increased 1.51 Bcf/d week-over-week. ResCom increased 2.84 Bcf/d, while Power demand decreased 1.58 Bcf/d. Industrial demand increased 0.25 Bcf/d.
- LNG exports decreased 0.04 Bcf/d week-over-week. Mexican Exports also decreased 0.02 Bcf/d.
Total supply is down 0.77 Bcf/d, and total demand is up 1.26 Bcf/d week-over-week. With the increase in demand and the decrease in supply, expect EIA to report a weaker injection next week. The ICE Financial Weekly Index report is currently expecting an injection of 38 Bcf for next week. Last year for the same week was a draw of 18 Bcf, while the 5-year average is an injection of 6 Bcf.