Noble Energy, Inc. (NYSE:NBL) Noble Energy's Acquisition of Clayton Williams Energy Conference Call January 17, 2017 8:30 AM ET
Brad Whitmarsh - IR
Dave Stover - CEO
Ken Fisher - CFO
Gary Willingham - EVP of Operations
Scott Hanold - RBC Capital Markets
Doug Leggate - Bank of America Merrill Lynch
Arun Jayaram - JPMorgan
Irene Haas - Wunderlich Securities
David Tameron - Wells Fargo
Brian Singer - Goldman Sachs
Bob Morris - Citigroup
Graham Price - Raymond James
Pearce Hammond - Simmons
David Heikkinen - Heikkinen Energy Advisors
Good morning, and welcome to Noble Energy's Conference Call. Following today's presentation, there will be an opportunity to ask questions. [Operator Instructions] Please note, this event is being recorded.
I'd like now to turn the conference over to Mr. Brad Whitmarsh. Please go ahead, sir.
Thanks, Savannah. Good morning, everyone, we're thrilled to be here today to discuss Noble Energy's acquisition of Clayton Williams Energy announced yesterday afternoon. The accompanying news release and slide presentation are available from our Web site. Dave Stover, Chairman and CEO will begin today's call by providing an overview of the transaction. Gary Willingham, EVP of Operations will provide a deeper dive into the geology, economics and our forward development plan. Ken Fisher, EVP and CFO is also here and will join for questions and answers.
I want to remind everyone that this event may contain projections and forward-looking statements as well as other non-GAAP financial measures. You should read our full disclosures in our latest news release and SEC filings for a discussion of those items. With that I'll turn the call to Dave.
Thanks Brad and good morning everyone and happy New Year. It's certainly been a great start to 2017 for Noble Energy. I appreciate everyone joining us today to discuss the complementary and value additive acquisition of Clayton Williams Energy. I would like to first recognize the personal leadership of Clayton Williams in creating a great company and the contributions he have made to our industry and the community, he and his team have built an impressive asset base and I look forward to working with him on a successful integration of the two companies.
Before we discuss the financial and operational benefit for the transaction I'd like to go over how we got here. Three years ago we made the strategic decision to increase our onshore U.S. oil exposure and take advantage of our horizontal development experience. This led to our merger with Rosetta Resources in 2015 and we're now adding another significant position with this transaction. We will hold the second largest position in the core of the Southern Delaware about a 120,000 net acres with a very attractive average entry cost.
Consistent with our disciplined approach Noble Energy has been highly selective in our assessment of various opportunities always maintaining our focus on quality and value creation. As we will outline today we believe this transaction is an excellent fit for our company. These are fantastic assets in the core of the Delaware Basin which we have had our eye on for some time. It presents the ability to leverage Noble Energy's unconventional development approach including long laterals, enhanced completions and integrated midstream to drive shareholder value.
Now looking at the slides, I will start on Slide 4. This transaction is a win-win for both companies. It brings together Noble Energy's investment grade balance sheet and two high quality acreage positions in the Southern Delaware. This will allow shareholders of both companies to realize accelerated and enhanced value creation. For Noble Energy this combination expands our position as a leading U.S. onshore operator with top tier acreage. The transaction provides benefits of scale, more than doubling our inventory and net unrisked resources in the Delaware, with highly contiguous acreage adjacent to our existing position the addition is in line with our bolt-on strategy and will increase long lateral development. The acquired acreage is also largely undedicated to third parties for midstream services. This will bring opportunities for ourselves and Noble Midstream Partners.
We have updated our four year operating plan that we presented in November to incorporate development of these properties. The result is an enhanced growth in cash flow profile. As you can see on the bottom of this slide our accelerated development plan for these assets increases each of our volume growth rates by 3 to 5 percentage points. Even more impressive the operating cash flow CAGR driven by the high margin barrels added accelerates even faster to 33% to 45% in the Basin upside plan, higher by 7 percentage points.
Slide 5 provides an overview of the added assets. The map on the right shows the acquired position in red, including 71,000 core net acres in Reece and Word County Texas which is adjacent to our existing acreage. Also shown is an additional 100,000 net Permian acres included in the transaction. The Southern Delaware position has a high working interest of nearly 80% and is over 95% operated. The expanded Delaware position adds 2,400 gross locations with an average lateral length of over 8,000 feet. Current net production is 10,000 barrels of oil equivalent per day with about half coming from the Delaware. This Delaware acreage has among the highest oil cuts in the basin at over 75%.
We provide transactions specifics on Slide 6. Given the complementary nature of the assets and the accretive impact to earnings and cash flow we believe this transaction is a very efficient use of our capital structure and balance sheet. Noble Energy will acquire all of the outstanding common stock of Clayton Williams Energy for $2.7 billion in stock and cash plus the assumption of approximately $500 million in net debt. We anticipate retiring this at or shortly following the closing.
The purchase price represents about $32,000 per core Delaware acre without allocating any undeveloped acreage value to the other Permian leasehold. Using $35,000 per flowing barrel existing production is valued at $350 million and we assigned $600 million in value for the Midstream business. The Midstream valuation reflects the planned infrastructure build out and gross volumes for Noble's accelerated development plan.
The transaction is anticipated to close in the second quarter of 2017 and I look forward to welcoming our new shareholders to Noble Energy.
Moving to Slide 7, I'd like to share a bit more on just how compelling this acquisition is for Noble Energy. Our management team has been very disciplined in assessing opportunities and focused on finding the right fit with the clear path to value creation. This announcement follows on the recent addition of 7,200 net acres in and around our existing position.
Now let me talk a moment about why we're so excited about the Clayton Williams Energy acreage. It all starts with the high quality of this rock. What really matters is location, location, location. Not only is this acreage adjacent to our existing position, it is highly contagious and as I mentioned it comes with a very high working interest and operatorship. And as we've seen in the basin rock quality, productivity and the mix of oil, gas and water can vary dramatically. The acreage benefits from high per-well recoveries which is confirmed by well control, the ability to expand long lateral locations, a high oil contribution and one of the lowest water cuts in the basin.
It is also one of the few opportunities of scale that we've seen in the basin largely free from midstream dedications. This allows us to apply our midstream competitive advantages and create value for us and Noble Midstream Partners.
Slide 8 shows the complementary fit of combining the acreage. Through the transaction we're establishing the second largest industry position in the Southern Delaware basin at 120,000 net acres. In addition to adding years of very high return opportunity to our inventory the acquired acreage will allow us to optimize development on our existing position. You can see on the map where the acquired acreage shown in red overlaps with our existing yellow acreage, and ultimately this leads to more efficient and longer later development. Our larger and more contagious position will allow us to further decrease our drilling days and optimize our cost structure even faster.
Turning to Slide 9, we outlined the impressive Delaware scale resulting from the combination. With this transaction we more than double our location count to over 4,200 future wells. Our net unrisked resource more than doubles to cover 2 billion barrels of oil equivalent. There is currently one rig operating on the new acreage which will bring total operated rig count for Noble Energy to four in the basin at closing. And we will continue to increase our activity level in the basin throughout the year, exiting 2017 with six total rigs or three on each position.
Let me now turn the call over to Gary who'll dive deeper into the assets and discuss our activity plans.
Thanks, Dave. Following on your comments about the high quality of this new acreage we know that all acreage is not created equal. That’s a simple statement, but it's an important truth. And through our extensive technical studies over the last couple of years we have a deep knowledge of the Delaware basin. This allowed us to opportunistically capture the Rosetta position 18 months ago, and has now positioned us to take advantage of a similar opportunity.
As you can see on the map on Slide 10, both the new and our existing acreage are located in the over pressured, low GOR area. Low water production in this area also contributes to a lower cost structure. This rock produces only 1.5 to 2 barrels of water per barrel of oil versus what can be as high as 4 to 7 barrels of water per barrel of oil in other parts of the basin.
Slide 11 shows the significant stacked pay running room and upside across the 3,200 feet of net pay. We provide a breakdown of the 2,400 future drilling locations on the acquired acreage by horizon. Consistent with the development plans on our existing acreage we expect the new acreage will support 12 wells per section in the Wolfcamp A, split between the upper and lower. The majority of value was allocated to the Wolfcamp A in our valuation. We also believe the Wolfcamp B and Wolfcamp C are both perspective across the acreage, which provides substantial upside. Additional upside potential also exists in the second and third Bone Spring, along with future well performance improvements in all intervals.
Slide 12, demonstrates strong industry well results from multiple benches, and I'll highlight a few key takeaways. There are several Wolfcamp A wells demonstrating the consistent productivity of the intervals across both acreage positions. In particular I would like to call your attention to the Collier 34-51 and the Geltemeyer 297 wells on the southeastern part of the acquired acreage. I'll discuss these on the next slide.
You will also notice several Wolfcamp B wells to the east, for IP rates over 1,000 barrels of oil equivalent today. And there are also a handful of Wolfcamp C wells, with an average IP rate of 700 barrels of oil equivalent per day. All three of these were potentially undersized fracs competed with well under 2,000 pounds of profit per foot.
We have also noted five new Noble Energy wells which recently commenced production. The wells utilized proppant concentration ranging from 3,000 pound to 5,000 pounds per lateral foot, including the Company's first Wolfcamp B completion. The wells are in the initial ramp up period, they are performing at or above expectations. We’ll have more information on these wells on our fourth quarter earnings call.
Turning to Slide 13, we show the compelling economics of the acquired Wolfcamp A inventory, with the rate of return at our base and upside pricing plans of 60% and 90% respectively, for a 7,500 foot lateral adding to the quality and depth of our inventory.
One of the reasons we were drawn to this specific transaction was the potential for long laterals which as you can see enhances both returns and NPV per well dramatically. The average lateral length of the new locations is 8,000 feet. For 7,500 foot lateral we have assumed an estimated ultimate recovery of 1 million barrels of oil equivalent for the acquired Wolfcamp A inventory. I want to highlight the Collier 34-51 and the Geltemeyer 297 wells, Clayton Williams' most recent completions. These Wolfcamp A lower wells are located on the southeastern area of the acreage.
The wells were completed using slickwater fluid and 2,350 pound of profit per foot on average. After three and five months of production the wells are outperforming our assumed 1 million barrel of oil equivalent type curve by 20% to 30%. And the cumulative oil mix is 80%. While it's still early, out performance has widened through time from shallower declines. And that’s something we’ve seen on our own enhanced completion wells.
But the presented economics we assumed an $8.5 million well cost, which includes drilling completion and facilities. As we’ve demonstrated in other basins I am confident we will lower this well cost over time. In fact we’ve already seen fantastic Delaware drilling result in the fourth quarter as we’ve transitioned through a continues drilling program on our existing acreage.
Our team demonstrated our best Delaware drilling performance yet, in the Monroe unit. A 10,000 foot lateral drilled in 25 days, which is the same time it took us to drill short laterals at the beginning of 2016. The 25 days is also 12% below our cost assumption. And given the magnitude and pace of learning curves that our teams have delivered in the DJ, the Marcellus and the Eagle Ford I know we're only scratching the surface in cost reductions from efficiency gains in the Delaware. Reductions can have a very significant impact on returns. $500,000 of savings moves the rate of return on our acquisition-type curve from 60% to 70%.
Moving to Slide 14. Noble's financial strength and flexibility which we maintained through the commodity downturn now provides the ability to increase activity and accelerate value on the new acreage. Following close of the transaction we plan to add a second rig on the acquired acreage by the middle of 2017 and a third towards the end of this year. This drives strong production momentum heading into 2018.
In fact we currently forecast 2018 production of over 30,000 barrels of oil equivalent per day for the new acreage. That's more than twice the current analyst consensus estimate for Clayton Williams Energy. Beyond acceleration Noble Energy has repeatedly demonstrated the ability to transfer unconventional expertise between U.S. onshore basins to drive differential competitive performance and we will deliver this once again. As shown on the slide we plan to increase lateral length by almost 50%, migrate to a 100% slickwater and more than double profit concentration per foot.
On Slide 15. We outline the robust standalone outlook anticipated for the acquired acreage through 2020 by year. You can see the dramatic volume growth on the asset in 2018 which is up a 150% from 2017 reflecting the anticipated two rig additions over the next 12 months. Not only does the asset grow to 60,000 barrels of oil equivalent in 2020 in the base plan and 70,000 barrels of oil equivalent in the upside plan we expect it to be net free cash flow positive beginning in 2018.
Moving on to Slide 16. The discussion around value would not be complete without mentioning the unique Midstream opportunity on the acquired acreage, which is largely undedicated for Midstream services. And as you know we are strong proponents of controlling our own destiny through infrastructure ownership. This strategy creates more operational flexibility, lowers our cost structure and ultimately the monetization of assets through NBLX enhances Noble Energy's financial flexibility. We provide an overview of acquired Midstream assets on the left which includes more than 300 miles of oil, gas and produced water gathering lines.
We expand on the standout Midstream opportunity on Slide 17, our plan to build out on the new acreage provides significant synergies and substantial dropdown potential in association with our ownership and Noble Midstream Partners. Noble Midstream broke ground on the first central gathering facility on our existing acreage last week which was anticipated to be operational by the middle of 2017.
Our approach on the acquired acreage will be consistent with the development which is currently underway. Based on the Noble forecasted pace of development we anticipate an incremental 3 to 5 central gathering facilities on the acquired acreage to support our long term growth objectives. That along with the associated gathering systems has been modeled to deliver cash flows equating to an estimated $600 million in midstream value.
Before I hand the call back over to Dave I'd like to highlight a pro forma view of the Delaware on Slide 18. I want to be clear the plans we communicated in November on our existing position are unchanged. With the acreage addition we now expect to end 2017 with six rigs in the Delaware basin and we'll bring on 50 new operated wells this year.
By 2020 the rig count grows to between 10 and 13 rigs. With the acceleration plan combined volumes grow to between a 145,000 and 180,000 barrels of oil equivalent per day by 2020, and that growth starts now.
With that I'll turn the call back to Dave.
Thanks, Gary. I will reinforce the impact this transaction has for the total company.
Slide 19 shows the broader U.S. onshore context. What stands out is we now have two core oil basins, 2 billion barrels of oil equivalent net unrisked resource in the DJ basin and another 2 billion barrels of oil equivalent net unrisked resource in the Delaware. With the 35% increase in drilling locations we now have an undrilled inventory of nearly 10,000 wells with an average lateral length of 8,000 feet and approximately 8 billion barrels of oil equivalent of net unrisked resource in our U.S. onshore portfolio.
On Slide 20 we show the significant enhancements to sales volume growth and cash flow acceleration as we aggressively develop our high quality inventory. As mentioned our new out is 3 to 5 percentage points higher across the board on volumes versus the November outlook represented in the red diamonds. I've still have not seen any peer approach or onshore oil growth outlook which is now increased to 28% in the base plan and 34% in the upside plan. This will also solidly put out total company volume CAGR into the double digits.
This growth contributes to enhanced company per unit margin and drives Noble's operating cash flow growth well in excess of our volume growth through 2020. This transaction adds an incremental 7 percentage points to our annual cash flow growth resulting in a CAGR of 33% to 45%.
I'm confident in delivering this plan, the acquired acreage is top tier and as Slide 21 shows Noble Energy is the right company to maximize its potential. We have a track record in enhancing value of acquired asset. Most recently with the Rosetta merger, where the team has significantly exceeded the original merger plan in a very short period of time. For example, we've already increased our 2020 expected Texas volumes by 80% to 120%, and increased our net unrisked resource by 50%. And as we show on the bottom of the slide Noble has differentiated well performance compared to the industry through the application of our unconventional expertise. Noble's operational capabilities can be counted on once again to deliver outstanding performance and value growth.
Turning to Slide 22, in summary I want to reemphasize the significant benefits of this acquisition. We are enhancing our position as the leading U.S. onshore operator. We've increased our core Southern Delaware acreage by more than 2.5 times and more than doubled our drilling locations and unrisked resources in this basin. This high quality new acreage is contiguous and adjacent to our existing position, supporting long lateral development with substantial midstream value.
We have planned to rapidly accelerate activity in 2017 and beyond, which further enhances our volume growth and cash flow outlook and will enable us to deliver substantial value to the shareholders of both companies. And as mentioned earlier the acquired asset are self-funding starting next year. So this is all additive to what we outlined in November.
Our industry leading onshore U.S. position combined with our world class Eastern Mediterranean Assets provides us with one of the most high value growth opportunities in our industry. This is supported by cash generation from our other global offshore assets. As we always have we will continue to actively manage our portfolio and focus on our high growth core assets, value maximization and maintaining a strong financial position. Noble Energy is uniquely position to deliver superior returns into the future.
With that Savannah we will open up the call for questions.
Thank you. [Operator Instructions] And we will take our first question from Scott Hanold of RBC Capital Markets. Please go ahead. Your line is open.
I was wondering, following the transaction, how do you all feel with your debt and leverage position? Are there assets in your overall portfolio that, I guess, become less core and could be monetization candidates?
Well I think there are. We’ll continue as -- if you look at our track record overtime we have always continued to look at the portfolio and address anything that wasn’t going to continue to compete per capital or we didn’t believe it was core. My believe is one everybody in the organization focused on things that are core to the company and can contribute to the growth of the company and that’s kind of the philosophy we’ve had for the last 10 years at least. And that’s how you’ve seen us continue to manage the portfolio and that’s how we’ll continue to do it going forward.
Okay. Then specifically on the debt and leverage?
Sure Scott, I’ll let Ken talk a little bit about his thoughts on that.
I think as you saw we moved through 2016 on I think a very successful basis, more or less managing organically cash flow neutral generated including Tamar 3.5% and about 1.5 billion of proceeds paid down, $850 million worth of debt and we’ll end the year in very strong liquidity position. And one of the agencies actually moved us up from negative to stable in December. So I think we are very much at a good shape.
What I liked about these assets were -- they were self-funding in the first full year and then with the margins they have their accretive-to-cash flow and as you look out '18, '19 and beyond they actually help your rating metrics. So I think we feel very comfortable, we’ve got the horsepower to bring these assets in successfully and continue prudent financial management.
Okay. Then as a follow up, what are the plans on this acquired acreage and even Noble's existing position in the Southern Delaware to test the extent of the other zones beyond the Wolfcamp A? I know you obviously mentioned you just did a Wolfcamp B. But what are the plans over the next year on this new asset base to look at what the upside could be beyond the Wolfcamp A?
Yes, Scott, this is Gary, I think you'll see us early on focused primarily on the Wolfcamp A. As we’ve said the vast majority or the undeveloped value has been ascribed to the Wolfcamp A, but there's certainly a lot of potential there in the Wolfcamp B and C as well, you know they've been some other activity in and around the acquired acreage that’s quite intriguing and I think you'll see us start to test that more as we get probably towards the end of 2017, early 2018.
Very similar to what we're doing on our existing acreage, you know we're just bringing on our first Wolfcamp B well right now in the existing acreage and I’m looking forward to talking about that on our first quarter earnings call. So I think you'll see a pretty similar path, but an accelerated path obviously now that we're going to be ramping up the six rigs versus the half a rig or so we ran last year.
Thank you, we'll take our next question from Doug Leggate from Bank of America Merrill Lynch, please go ahead line open.
So congratulations, Dave. I've got a couple of questions also. I wonder if I could just dig into one of Scott's questions a little bit more. Relative capital allocation, I'm thinking specifically Deepwater, Gulf of Mexico versus the accelerated pace onshore and just as part of that answer, I wonder if you could address the seemingly non-core acreage in the Clayton Williams portfolio, I guess that's Central Basin platform. And I've got a follow up, please.
I think this is all consistent with what we talked about in November as our capital allocation, that's right now, it’s focused in the DJ, the Delaware and Eastern Med. I think from an offshore perspective you know with the development of Leviathan, will take the majority of offshore spending and then we'll have -- we actually have a nice opportunity for an exploration well most likely, offshore Surinam this year.
I think part of that is driven by where we are in the stage of development of some of the projects. Don't forget we just came off bringing on three major projects in the Gulf of Mexico and one in Equatorial Guinea over the last year, a year and a half. So I think we're pretty clear on where our capital's going to.
From the disposition of assets I think its -- same thing we’ve talked about, if somebody else can create more value out of it than we can based on how the investment scenario plays out for somebody else relevant to their portfolio then we'll accelerate value for our shareholders by doing that. We have a history of doing that and so I don't think that's any different than what our history has been, and again it's about focusing on these key areas where we can grow the business and where we're allocating our capital and then maximizing the value out of the other areas.
Got it. Thanks, Dave. My follow up, hopefully a quick one is just the timing of delivering the synergies in the drop-down from the midstream? I'll leave it there. Thanks.
I think the synergies we talked about, most of those are driven by the interest savings that you look at, so that'll be pretty quick. I think as far as timing of drop-downs and stuff, that'll play out over probably the next two to three years or so. I think -- the nice part about it is that midstream business will grow hand-in-hand with the development of our assets and you can see the accelerated pace we have on the development of the assets, so that's going to push that along pretty quickly.
And our next question comes from Arun Jayaram from JPMorgan. Please go ahead, your line is open.
I guess it's Permian acquisition day, Exxon with a big Permian announcement just now. Real quick on the 2018 plan, I wanted to get a sense of anticipated completion activity for the Noble and Clayton Williams acreage? It looks like you're spending around $750 million combined. How many completions do you expect to get in the Delaware?
I think we've said we'll bring on 50 new wells in 2017 in the Delaware.
I think, 2018, I saw that just in 2018?
Okay. 2018, I don't have the number right in front of me, but given that we're 50 in 2017 with probably an average of 3.5 to 4 rigs, you're probably easily going to be around 70 or so in 2018.
Great. Thanks for the color on that. Just my follow-up question is just on anticipated oil cuts. Gary, you highlighted in the deck, 75% oil cuts. Is that over the EUR? Or is that the initial oil cuts that you're seeing or expected to see on these wells?
Yes, when we talk oil cuts we talk over the life, over the EUR.
And we'll take our next question from Irene Haas from Wunderlich Securities. Please go ahead, your line is open.
Congratulations on getting a hold of this really nice piece of real estate. The question has to do with lockouts to insiders from Clayton and Ares. Any restriction as to when they can sell the stock? Then also, what has to take place before you close the deal during second quarter of 2017?
Yes Irene, I just refer anybody for any specifics to go to the agreement and take a look at that. I won't address anything specifically there. But what was the second part of the question?
Any, I guess, lockup, I guess it's the same thing, just go to the filing, right?
Okay. Then if I may, just kind of what prompted you to make this decision? Does it have anything to do with the fact that Clayton Williams sort of jettisoned their Eagle Ford assets in December?
No, I think it's really been a function of -- if you look just over probably the past three years we've been focused on what would be a good addition to build out a solid core oil position in combination with what we have and we love in our DJ position. And follow-on to what we did with Rosetta, this acreage -- this Delaware acreage of Clayton Williams was right at the top of our list and it's pretty obvious when you look at the map why that would be. Especially in the fairway of kind of the core position out here, and so we just continued to have our eye on that and same thing as Rosetta, we were in a position where as the timing was right we were able to move quickly and that benefitted us in 2015 and I think that benefitted us now too, doing the homework and being ready to move when the opportunity presents itself.
And our next question comes from David Tameron with Wells Fargo. Please go ahead, your line is open.
Just a question, philosophically, I know you kind of talked about this in November, how should we think about additional CapEx? I know you talked about the rigs, but as far as CapEx versus cash flow 2017, 2018, how you guys thinking about that at a $50-ish kind of number. $50, whatever you want to use?
Yes, I think over that period of time with the plan we have led out we believe we can well manage within overall cash flow. All things considered, we’ve got some divestments plan, we’ve got some sell-downs still plan for some of the assets in the Eastern Med which help fund that portion and then additional drops from the midstream. So including all of those elements I think we can manage within cash flow in that $50 to $60 range and deliver this plan we’ve laid out.
Okay. Thanks. Then just getting back to the proppant, I know there's obviously a debate on what the right numbers is, the 3,000, 5,000, whatever that happens to be. But if I start thinking about doing something at 5,000 rather than 3,000, there's obviously an additional cost to that, when you start talking about 7,500 foot. Have you -- I guess, what's the additional costs, I guess, if you're doing a 5,000 versus 3,000? What are you paying for sand? Or ballpark, what's the spot market?
And am I correct in thinking about obviously there is a trade off in additional cost versus EUR and right now is that a break even number? Is it break even today with the hope that it gets better? Is it right now it makes sense to go with the higher -- can you give me more color on that?
Hey David its Gary. I think we are still working through that to some degree. If you’ll recall on our call in November for really the DJ and the Delaware both we showed plans to test higher proppant concentrations in the DJ we showed some results in both Mustang and Wells Ranch of much higher proppant concentration jobs and how they were outperforming this high curve, so I think there is no doubt from what we’ve seen early on that we can increase EURs with higher proppant concentrations and then we’ve traditionally pumped in each area. Obviously it does come at higher cost. We're most focused clearly on what the right value decision is.
So that’s one of the reasons why in November we hadn’t upped our type curve yet to reflect those higher performing higher proppant concentration jobs. We want to get comfortable that the values is there. We are following that same path really in the Delaware, we’ve mentioned that type curve is based on 2,000 pound per foot, both on our existing acreage and on the Clayton Williams acreage and yet we are testing higher proppant concentrations than that on our own acreage, as we’ve said 3,000 to 5,000 pounds and those well initially are performing at or above expectations and we’ll talk a bit more about that on the next quarterly call.
We also showed the two wells from Clayton Williams that are completed at a little more than 2,000 pounds on average 2,300 pounds or so on average and you can see they’re outperforming the type curve too. So again I don’t think there is any doubt we can improve the EUR with more concentration of sand, but obviously it comes with a cost more focused on the right value, so more to come.
Our next question comes from Brian Singer with Goldman Sachs. Please go ahead. Your line is open.
Two questions, first in your revised guidance and then in how you're thinking about capital allocation, is really the only change here adding capital activity in the Permian? Or are you either explicitly or thinking about making adjustments elsewhere? Then as the CapEx increased to source the improved CAGR, about the $300 million a year going forward that one would back into based on $150 million for half a year this year?
Brian, first part of that is, all we did wad add in the capital assuming a second quarter, sometimes second quarter closing date on this for these properties to what we showed in November. So I guess the other part of that is, I think we laid out, I forget which slide it is, but we laid out an expected capital ramp for these properties.
Brian it's on Slide 15, so we showed the capital ramp on the acquired assets under both the base and the upside plan and again the difference in the base and the upside plan is whether we ramp to five or six rigs by 2020. So you can see the capital by year just for the acquired assets. As Dave said, that's really the only change that's incremental to what we laid out in November.
The nice part here Brian is and the same thing we saw a little bit from the Rosetta, is that these properties start in 2018 to fund themselves, so it's all additive and not a reallocation of things. We added to what we showed, layered on this, plus additional 7,200 acre acquisition that we picked up here earlier this year and that's what's driving the incremental growth rate.
This is Ken, Brian. As well I think just to clarify this is also additive from a NBLX standpoint, it doesn't change any development activity on the DJ acreage nor on the existing Noble acreage in the Permian from an NBLX standpoint and what you're doing is adding about 60,000 barrels a day of midstream opportunity to NBLX in 2020. So pretty material impact and again additive.
Dave, when you built the Wattenberg position, you had the Patina acquisition and you followed up with the U.S. Exploration acquisition. You were pretty upfront, post Rosetta, that you saw that deal as a starting point in the Permian. Does this transaction give you the sufficient scale that you need? Or is this still whetting [ph] the appetite from where you ultimately want to be?
This gives us scale, I mean there's not a -- you look at it and with this position of a 120,000 acres you now have 2 billion barrels of resource just like we have in the DJ positions. So you’ve got two of these positions now with 2 billion barrels of resource and at the same time you're the second largest and not far behind number one in the Southern Delaware, which we see this acreage fitting right in the core of the core here.
Great. Thank you very much.
Thank you, and I'll take our next question from Bob Morris with Citigroup, please go ahead your line is open.
Again, congratulations, Dave. I just want to follow up on the question regarding the proppant here and its two questions. One, I know you addressed Dave's question and said there would be more to come in subsequent quarters, but as far as what you need to see to step up to higher proppant load, could you make that decision in the second half of this year? Is that a point where you would have enough data to, say you have 3,000 to 5,000 pounds as the level, we want to use going forward?
Yes Bob, this is Gary and I think really to get comfortable with the value proposition of it. We'd like to see to a good 6 to 12 months of data on these wells to convince ourselves that it's clearly adding value. So if you think of the Delaware Basin itself, we're bringing on the first 3,000 to 5,000 pound jobs in the -- we brought them on in the fourth quarter of last year. So yes, probably third or fourth quarter of 2017 we'll start to have to a better feel given that it's been a bit longer than that we pumped the first ones in the DJ, we may know something more there earlier than that even.
Then, Gary, on the three rig program you're running on your own acreage apart from this deal today, how many of the wells under that three-rig program are still or will continue to test higher proppant loads in the 3,000 to 5,000 per pound foot range?
I'd say the vast majority of them are in the 3,000 plus range.
And we'll take our next question from Graham Price with Raymond James. Please go ahead, your line is open.
From what you have seen so far, is all of the core Delaware acreage prospective for the development plan zones that you mentioned in Slide 11? I was just wondering that if not, what's the break down there between Wolfcamp A, B and C and maybe possibly the Bone Spring?
This is Gary again. I think the acreage is certainly all prospective for Wolfcamp A upper, A lower, B and C as we've said we've allocated most of the value at this point to the Wolfcamp A which gives us a lot of upside for the B and C. For the Bone Spring zones we haven't put much into that yet, most of that is a bit further north I think. So we'll see where that development leads to, but certainly some more potential upside there as well.
Then for a quick follow up. Just thinking about operating costs, should I assume that those are similar within the acquired acreage as to what you're seeing in your legacy Delaware position?
I think it's going to be very similar. The development plan is going to be very similar to the types of facilities that we're building and it would be very similar with water well ratios kind of in the same range, so I think you'll see pretty similar costs.
And our next question comes from Pearce Hammond with Simmons. Please go ahead, your line is open.
You had a good slide in your deck highlighting the value you've added since the Rosetta transaction. So I was just curious, real big picture, but what do you feel like you've learned from the Rosetta transactions that can be applied here, that can add even more value?
Yes, Pearce I think it's a long list. I think when you look at -- we took our time, initially all the Rosetta acreage to convince ourselves that it was as good a quality as we suspected it was all along. We drilled a number of wells across it and we tried different completion designs, different profit loadings, we're just now starting to see the benefit of moving to development mode, and pad drilling and long laterals.
And so I think there has been a tremendous amount of learning and tremendous amount of additional value created on the acreage since we acquired it from Rosetta, I think that's a follow-on from what you saw in the Marcellus after we move there from the DJ, it’s what we talked about earlier, and how we continuously, very quickly transition learning's from one basin onshore to another, that's the benefit of the portfolio we've got and I think you'll see the exact same thing on the Clayton Williams acreage as we start some ramp up development there.
Then my follow up is on the $75 million of synergies that you alluded to this before the majority of it was the interest [ph] expense reduction. But how much of the $75 million is G&A savings?
Very little at this point. I think from a G&A perspective we just need to get together with the Clayton Williams' team and start to work through that, we've putting an integration team together to -- very similar to how we did with Rosetta, it worked extremely well to get both sides together and then evaluate how do we want to run things.
Thank you. Our next question comes from David Heikkinen with Heikkinen Energy Advisors. Please go ahead. Your line is open.
Just on the synergies in the midstream, you show on the slides that it excludes NBLX estimated capital. I was assuming that Noble would actually invest capital to those three projects and then drop. Is it assumed that there won't be any Noble Midstream capital?
Yes Dave this is Brad Whitmarsh. We have included in our capital outlook is Nobles' portion and ownership in those midstream build outs. So we have not include NBLX’s ownership interest in the various development companies as that gets built out.
Okay. So the three projects you talked to are roughly $150 million to $250 million in NBL Capital, is that fair?
They’d be --.
It's at 8.8.
That’s more like gross capital acreage then on a pro rata basis NBLX will fund its piece, than Noble will fund its piece.
Got you. That's an 8.8 number. I'm just curious, in the area, given you're ramping considerably and it does fit into the midstream, just water sourcing and kind of the thought process around slickwater sourcing?
First of all, we’ll be recycling much of what we produce and so we’ll have that as a source. And then on our existing acreage we’ve been able to acquire water resources locally. So we don’t anticipate any issues there.
And it appears we have no further questions at this time. I'll turn it back over to you Mr. Whitmarsh for any additional or closing remarks.
Great. I want to thank -- thank you everybody for joining us for this morning's call. Megan Repine and I are around all afternoon and the rest of this morning for questions and follow on and we look forward to talking to many of you. Thanks.
The conference has now concluded. Thank you for attending today's presentation. You may now disconnect and have a great day.
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