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PDC Energy Inc  (NASDAQ:PDCE)
Q1 2019 Earnings Call
May. 02, 2019, 11:00 a.m. ET

Contents:

  • Prepared Remarks
  • Questions and Answers
  • Call Participants

Prepared Remarks:

Operator

Good day, ladies and gentlemen, and welcome to the PDC Energy First Quarter 2019 Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. (Operator Instructions) As a reminder, this conference is being recorded.

I would now like to turn the call over to Michael Edwards, Senior Director, Investor Relations. You may begin.

Michael Edwards -- Senior Director of Investor Relations

Good morning, everyone, and welcome. On the call today we have: Bart Brookman, President and CEO; Lance Lauck, Executive Vice President; Scott Reasoner, Chief Operating Officer; and Scott Meyers, Chief Financial Officer. Yesterday afternoon, we issued our press release and posted the slide presentation that accompanies our remarks today. We also filed our 10-Q. The press release and presentation are available on the Investor Relations page of our website, pdce.com.

I'd like to call your attention to our forward-looking statements on Slide 2 of that presentation. We will present some non-US GAAP financial numbers today, so I'd also like to call your attention to the appendix slides of that presentation, where you'll find a reconciliation of those non-US GAAP financial measures. In regards to proxy matters as well as to access materials, please go to the website (inaudible) 4pdce.com.

With that, we can get started. I'll turn the call over to Bart Brookman, our CEO.

Barton Brookman -- Chief Executive Officer

Thank you, Mike. Good morning, everyone. First quarter 2019, a strong quarter for the company and on target with our expectations. Today, the team will give details on the quarter and outline significant steps in our ever improving outlook. These include: enhanced capital efficiency in both basins; the company's operational excellence, we brought on a series of tremendous wells in the first quarter; cost improvements; free cash flow outlook; and our financial strength. I hope you leave today's call with a clear understanding of the tremendous opportunities the company has for ongoing success for many years to come.

Let me start with some quarterly highlights. When compared to the first quarter of 2018, a 26% improvement in production for the company, to 11.2 million barrels of oil equivalent or 125,000 Boe per day. Wattenberg production improved 30% when compared to the first quarter of 2018. This is primarily due to the strong work of our operating team over the last 12 months, along with the ongoing improved line pressures related to DCP's Plant 10 start-up, which occurred last August.

In Delaware, production improved 20% year-over-year and our drilling and completion efficiencies continue to make tremendous progress, with improvements in our drill times and completion designs. Also in the Delaware, our oil marketing arrangement continues to shine, leading to strong netbacks for the quarter of 97% of WTI. From a financial perspective, adjusted EBITDAX, $209 million, LOE $3.14 per Boe, G&A improved dramatically from 2018 levels, to $3.53 per Boe, capital spend for the quarter, $282 million. This is slightly ahead of our plan due to ongoing improvements in our drill times and completion efficiencies in both basins, but we're on target for our $840 million spend for the full year. Both Scott and Scott will give a lot more detail around the operating and financial aspects of the company in a moment. Last, I'd like to thank both operating teams in Texas and in Colorado as well as our EH&S group for a terrific quarter. Safety performance was outstanding and the Wattenberg has gone over one full year without a loss time injury.

Next, our Delaware midstream monetization process. Last night, we announced we've reached agreements on two of the three components, natural gas gathering and processing and water gathering and disposal. Approximately $310 million worth of proceeds, two reliable midstream partners: EagleClaw for gas; WaterBridge for water management. Very important, both agreements offer very competitive fees that will not adversely impact our operating margins. I will let Lance give a lot more detail on these two transactions in a moment.

So, what to expect for the balance of 2019? We're on target for our 48 million barrels of oil equivalent production level. Oil mix of 41% to 45%, DCP's Plant 11 is anticipated to come online in June and we expect strong production response related to the start-up of this plant. We anticipate PDC's cost structure, both LOE and G&A to continue improving throughout the year, and expect capital discipline as we're committed to our $840 million spend levels as we pursue free cash flow for the company. If oil remains above $60 a barrel, expect us to exit 2019 in an incredibly strong financial position.

Finally, I want to briefly discuss the strength of the current PDC Board and the tremendous confidence I have in our leadership team. As you are aware this year, an activist shareholder has nominated opposing slate of three Director candidates to stand for election at our annual upcoming meeting. After a thorough review of their proposed candidates, we determined that our current Board already possesses the necessary skills, expertise and background best suited to steer PDC. Since becoming CEO in 2015, I've worked closely with our current Board members approximately 50% of whom, I've been refreshed in the last four years. I've seen firsthand, our Board's depth of experience in the critical areas of our business and the diversity of thought they bring to our organization.

I've also watched the thoughtful and serious way each Director participates in developing the company's strategy, guiding and overseeing PDC on a regular basis. These efforts have directly led to the strength of the company today and our promising outlook tomorrow. There is no doubt in my mind, this Board is the right group to navigate specific challenges and opportunities we are faced with at this time. With PDC's strong Board, management team and employee base, I'm extremely confident in our ability to deliver shareholder value. In the weeks ahead, we look forward to continuing our dialog with PDC shareholders. We're also grateful for the positive feedback and strong support we've received in our discussions to-date. I'd like to remind everyone that the purpose of today's call is to discuss our financial and first quarter results and our very positive long-term outlook. With that in mind, when we open up the call for Q&A, we ask you focus on our current business plan. Thank you in advance for your continued support.

With that, I'll turn the call over to Scott Meyers for a financial update on the company.

R. Scott Meyers -- Chief Financial Officer

Thanks Barton. Starting on Slide 7, we show our US GAAP metrics for the first quarter 2019 compared to our 2018 levels. As you can see, we had a 5% increase in our total sales between periods. We were especially proud of this growth, considering the 16% drop in prices over the same time period. Net loss for the quarter was $120 million, and as we'll show in a minute, this is due to the changes in the value of our unsettled derivatives.

Finally, we show our G&A both in terms of absolute dollars and per Boe, compared to 2018. Our G&A is down 12%, more on this in a moment. Shifting to our non-GAAP metrics, you can clearly see on the charts changes in NYMEX oil over the past year, that I just alluded to. Our adjusted EBITDAX and adjusted cash flow from operations, each came in at approximately $200 million. Both of these measurements have grown year-over-year as a result of our production growth outweighing the decreases in oil price. Adjusted net income which came in at $18 million for the quarter compared to only $3 million in the prior year strips out the aforementioned impact of the changes in the value of our unsettled derivates.

There are a couple things to point out in terms of operating expenses for the quarter. First, our LOE per Boe of $3.14 represents a 6% decline from the first quarter of 2018 and is on track for our stated goal of $3 or less. Our Wattenberg LOE of $2.63 is starting to return closer to our historical run rate, thanks to a more manageable operating environment. Scott will give more color on this in a minute. In Delaware, our absolute LOE dollars actually decreased sequentially from the fourth quarter of 2018 to the first quarter of 2019. The increase in LOE per Boe is purely due to the decrease in volumes as a result of the turn-in-lines timing late last year. Last, our TGP between periods increased primarily due to an increase of our oil volumes on pipe. Obviously, this is something we strive from a community and an environmental standpoint and we're confident with our full year range of $0.80 to a $1 per Boe.

On Slide 10, I want to take a minute to go into more detail about our G&A, which obviously has become a very important issues across the sector. Clearly as the industry adapts to the new paradigm, G&A represents one of the few costs that we are able to directly control to preserve and enhance our margins. On the top right of the slide, you can see that we've made significant strides in our annual G&A per Boe, which has improved 45% since 2015. Looking at our quarterly trends, our first quarter 2019 G&A of approximately 350 per Boe is down considerably quarter-over-quarter.

Looking at the first quarter in more detail, you can see we've highlighted several buckets of our expenses. Approximately 25% -- our $0.25 per Boe or roughly 7% of our first quarter total is what we classify as short-term in nature. This is directly related to our Delaware Midstream divestiture which we expect to deliver tremendous value to the company as well as ongoing shareholder activism costs. Another $0.25 per Boe is tied to investments and scale and proved efficiencies, most notably the implementation of our ERP system.

As we've mentioned in the past, these are investments made in 2018 and 2019 to help set PDC up for the future. Finally, we invest $0.30 per Boe in being a responsible operator particularly in Colorado. This includes our EH&S efforts as well as our community and government relation groups. These ESG dollars are a core component of running a successful respected publicly traded company and will remain a vital part of PDC moving forward. All of these considerations were included in our 2020 G&A target of -- or at $3 per Boe. When considering G&A and non-cash G&A as well as the differences between successful efforts and full cost accounting, we're happy with the progress we've made and project to continue to make in the years to come.

Shifting gears to the balance sheet and financial guidance on Slides 11 and 12, there are just a few things I want to call out. Currently, we're approximately $125 million drawn on our revolver after outspending to the tune of $90 million in the first quarter, right in line with our budgeted expectations. As we covered in the press release issued last night, we expect to utilize the upfront cash proceeds from the Delaware midstream monetization to pay down our revolver at the time of the expected closing. Assuming $55 crude, we expect to outspend again in the second quarter, prior to generating free cash flow in the second half of the year.

In a minute, I'll go over our two-year outlook, at $55, which shows full year free cash flow generation of approximately $65 million in 2019. As you can see, we have a very strong 2019 and 2020 oil hedge program and we just started our 2021 program. In terms of our 2019 financial guidance, we are currently on track to meet each of these cost ranges as well as our projected commodity mix. It is worth nothing that our oil price realizations were very strong in the first quarter, highlighted by our Delaware basin realizations of 97% of NYMEX.

As we announced on our press release and Bart briefly mentioned, we've announced our intent to return capital to shareholders via a stock repurchase plan. This program is approved for up to $200 million, with a targeted completion time frame of the third quarter of 2019 through year end 2020. Importantly, and as a differentiator to many of our peers, we intend to fund this program through free cash flow that we project to generate over this time period. While we believe, this is a strong statement regarding the confidence in the depth and the quality of our inventory, it is also important to note, that given our strength of our strategy and our current operating plan as well as current crude prices, this does not roll out the potential for optimistic inventory add and additional returns of capital to our shareholders in the future. We'll have more detail on this in coming quarters, but at this point, we plan to complete this repurchase through two tranches. One will be executed systematically and one will be a bit more optimistic and dependent upon market conditions.

On Slide 14, we now show our two-year outlook updated from $50 to $55 oil due to the material change in crude pricing since the last time we presented. As you can see, our free cash flow, free cash flow margin, growth per debt adjusted share have all increased in both years compared to what we introduced last quarter. We believe these are all top tier. It's worth pointing out again, that our 2020 capital plan which is slightly higher than our 2019, includes allowance for increased activity due to the operational efficiencies which you'll see in a minute.

With that, I'll turn the call over to Scott Reasoner.

Scott Reasoner -- Chief Operating Officer

Thanks, Scott and good morning, everyone. We're now on Slide 16. As both Bart and Scott have mentioned, we had really strong results and performance that has led us to a solid quarter compared to our internal expectations. Production of approximately 125,000 barrels of oil equivalent per day and 40% crude, represents nearly 20% oil growth year-over-year. In the Wattenberg, we averaged 100,000 barrels of oil equivalent per day and had 38 spuds and 32 turn-in-lines, while in the Delaware, we spud 10 wells and turned-in-line nine for a total capital of $145 million. This included approximately $20 million related to our midstream assets. As Lance will touch on in a moment, avoidance of future capital investment in our midstream assets will help in our continuing efforts to control our capital spending.

We show a little more detail around our quarterly production in LOE on Slide 17. As you can see, we grew over 25% on an annual basis. First quarter production included modest sequential growth from the Wattenberg, while Delaware volumes decreased from the fourth quarter of 2018 due to our turn-in-line schedule. As I just mentioned, we did have nine Delaware turn-in-lines this quarter that are expected to provide solid growth in the second quarter, as we're currently averaging more than 30,000 barrels of oil equivalent per day. In terms of our LOE, we're getting back toward our more typical run rate especially in Wattenberg. Both basins were in line from a total expense standpoint with Wattenberg decreasing and Delaware increasing and LOE per Boe due to the volume profile we just covered.

Moving to slide 18 in a more detail into Wattenberg, we are very pleased that our first quarter well costs have come in around $100,000 to $200,000 below budget. This may not seem like a big improvement, but when you consider our 2019 program has approximately 120 turn-in-lines, it quickly adds up to material savings. In the first quarter, we're a bit ahead of schedule on completions leading to slightly accelerated cost compared to budget. We plan to keep an eye on both these trends as we move through the year. As it stands, we have the ability to flex our completion schedule to ensure we stay within our capital budget.

From a midstream perspective, overall performance has been pretty solid to start 2019. DCP's O'Conner Plant 11 and Big Horn Plant 12 are on track for June 2019 and mid 2020 start-up respectively. And as you can see on the graph on Slide 19, the overall trend on PDC gross gas volumes is up from last summer, while average Kersey Line Pressures are down. If you focus on the red circle, we highlighted the span of a couple of weeks that had severe weather and planned down time. Similar to the last time we showed this chart, you can see the impact of both volumes and line pressures when the system is not operating at close to 100%. This is to say, that while the operating conditions are improving, we're still eagerly awaiting the start-up of Plant 11, Plant 12 and other non-DCP plants over the next year or so.

Switching to Slide 20 and the Delaware, you can see we have a very similar story. From a well cost perspective, we have been executing better than planned as we're approximately 5% below budget. Similar to Wattenberg, these trends have our full attention and we will continue taking the necessary actions to stress our capital discipline. At this point, in order to offset an additional three or four wells that we project to spud compared to budget, we have decided to delay the completion of our seven-well Tinman project in favor of a four-well pad in our North Central area. As a result, the Tinman -- I'm sorry, as a reminder the Tinman is an MRL pad and the new four-well pad is all XRLs. This change in our completion schedule results in an immaterial change to our forecast production in 2019 and 2020. With both per well D&C cost and midstream capital savings in 2019, offsetting the drilling pace. This decision is a perfect example of our commitment to capital discipline and execution of our strategy.

Moving to Slide 21, we show improving trends on both the drilling and completion side of things. Keep in mind from the time of our acquisition, which closed in December of 2016, we've taken several measures to arrive at where we are today. First, we had to right-size our drilling fleet to get the horsepower and equipment needed for our development. Second, we've successfully transitioned from single well acreage holding mode to pad drilling in a focused consolidated position. Third, we've modified our completion design to wider stages with similar proppant loads. These are all normal course of business for a new entrant into a basin. And I want to commend our team for achieving these results.

In terms of drilling, we continue to focus on drilling longer laterals and have improved on our average drill times from spud to rig release by 40% since closing. Keep in mind, this is not normalized to reflect the increased laterals, so our per foot numbers would be even stronger. We've coupled that improvement with a 40% improvement in our average completion cost per foot. This is a testament to both our completion crew, which has been clicking on all cylinders and the utilization of local sand, which saves us a couple of $100,000 per well.

A final note, we have recently drilled an MRL well in 19 days and an XRL in 22 days from spud to rig release. These are well below the average and provide the line of sight for future reduction in drill days and thus costs. In addition, our use of in basin sand and longer stage lengths continue with a watchful eye on well productivity. This has the potential to further reduce costs. With these efforts, we expect our costs to continue to come down through the year.

Before turning the call over to Lance, I want to spend a little time discussing some of our recent well results. First is our Windy Mountain pad. As you can see on the map, these XRL wells are located in close proximity to our Grizzly pad in Area 3 of Block 4. As we mentioned, when originally discussing our Grizzly results, some of the valuable learnings we captured in this low GOR, included differentiating between the upper and lower Wolfcamp A. The Windy Mountains targeted the Lower B and are producing approximately 165,000 barrels -- I'm sorry, 165 barrels of oil equivalent per day, per thousand feet and 60% oil. These are strong wells above our expectations for the area that have us encouraged as we look toward completion of the Tinman wells in early 2020.

Next, we have the Argentine pad in Area 2. This pad includes both a Lower B testing and accelerated flow back technique and our first well testing the third Bone Spring. In terms of the Lower B, you can see this well is averaging well over 200 barrels of oil equivalent per day per thousand feet and an impressive 75% crude oil. Meanwhile, our Bone Spring well which is yet to reach peak production is averaging just under 200 barrels of oil equivalent per day, per thousand feet and 70% oil. These results while extremely early have us very excited about the prospectively of these benches.

I want to instill a bit of caution before we assume this Bone Spring test could add a large amount of inventory. It's very important to realize that as we continue to figure out the long-term ramifications of the parent-child and child-child relationships, successful Bone Spring wells may simply improve our total returns per section, without increasing the absolute number of wells per section. Look for us to continue evaluating data from these wells as well as the drilling of several Bone Spring tests in 2019 with completion in 2020.

All in all, I'm extremely proud of our teams and the tremendous results they are delivering. We just went through lower cost per well from improving drilling and completion times in the Delaware, terrific Delaware well test and an improving Wattenberg midstream environment. All of which, we expect to drive strong performance through the rest of the year and into 2020.

With that, I'll turn the call over to Lance to review our midstream transactions.

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Thanks Scott. We're very pleased that we've executed definitive agreements to sell our gas-related midstream assets to EagleClaw Midstream and our water related midstream assets to WaterBridge. Both EagleClaw and WaterBridge are two premier midstream providers that have substantial existing, large scale midstream infrastructure in the Delaware basin. Additionally, both parties are already providing midstream services for PDC in our eastern area.

The combined purchase price for both transactions totaled approximately $310 million, of which $225 million will be an upfront payment at closing and the balance of $82 million as an unconditional payment one-year from closing. Additionally, PDC can earn up to a combined additional $135 million through pro forma space incentives over the next several years. The structure of the long-term service agreements include an AMI, no volume commitments from midstream services, midstream operational performance terms and fee-based contracts. We anticipate closing mid-2019. The slide also highlights several key benefits to PDC. Cash proceeds in both years strengthen our balance sheet and fund operations. Market competitive third-party fees which is important to us, as we did not want to dilute our strong margins. One of the key provisions of the service agreement is takeaway flow assurance and access to major gas markets. Finally, these transactions result in the avoidance of substantial future midstream capital to PDC, which we estimate at $50 million to $100 million per year over the next several years.

This next slide highlights more the details of the two midstream asset transactions. It includes the specific proceeds and incentives for both the gas and water transactions. Looking at the service agreement provisions and first for EagleClaw, we've executed a 20-year contract that provides multiple gas-related midstream services. Additionally, we've committed a portion of the company's projected future, Delaware basin residue gas volumes to a long-term transportation agreement on the Permian highway gas pipeline. This pipeline with the projected start-up of fourth quarter 2020 will transport a portion of the company's residue gas volumes from Waha to premium Gulf Coast markets. Now looking at WaterBridge, we've executed a 15-year contract that provides multiple water related services, including gathering, disposals and an option for recycled water back to PDC for completion operations. Importantly, we anticipate that 100% of our produced water will be transported via pipe.

Finally, I want to note that we're in the final stages of negotiations with a third midstream provider to acquire our Delaware basin crude oil gathering assets. In closing, I want to thank our midstream, marketing, construction and legal teams for the tremendous work and success of our Delaware midstream asset divestiture program as these transactions represent tremendous value add for PDC.

The structure of the transactions are balanced. They include upfront cash, incentive payments, market-based fees and avoided (ph) midstream capital. I also want thank Jefferies as PDC's exclusive financial advisor in connection with these transactions. We're very pleased to have entered to long-term partnership with EagleClaw and WaterBridge, again, both of whom are premier midstream companies with great operating teams and significant in-basin infrastructure. And again, we look forward to finalize our crude oil gathering asset sale in the near future.

So with that, I'd like to turn the call over to the operator for Q&A.

Questions and Answers:

Operator

Thank you. (Operator Instructions) And our first question comes from Welles Fitzpatrick with SunTrust. Please proceed.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Hey, Good morning.

Barton Brookman -- Chief Executive Officer

Hi, Welles.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Sticking with the midstream, can you talk to the minimum levels of activity on the EagleClaw contract and also could you talk to, whether the kind of back half and I guess preliminary 2020 plan for two rigs would hit some or all of the incentive bonuses?

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Yes, Welles, This is Lance. Our incentive payments, the way that we structure that is for one of the companies who has been with EagleClaw to be based upon volumes that are produced above and agreed to volume that's in our agreements with them. And so as we look at our activity going forward and we look at the volumes that are the minimum that are part of that contract, also when we exceed that minimum amount, then we get into the incentive payments. The incentive payments will then go over a significant number of years and there's a lot of different factors and criteria that go into that. But from where we sit today, we're pleased with how it's structured and we think it's something that we'll be able to gain value with overtime.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Okay that makes sense and I'm going to throw a Hail Mary here, but if there's any chance you could guide us in on oil gathering, what that EBITDA might look like, so we might be able to model in some sort of transaction?

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

I appreciate that Welles. Yes, we're not providing any EBITDA factors or numbers associated with the crude oil gathering system. But clearly, we're in the very final stages of negotiations with that third midstream provider and I hear very soon, we'll be able to announce the results of that.

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Fair enough. Appreciate it. Thank you.

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Thanks, Welles.

Operator

Thank you. And our next question comes from Brian Downey with Citigroup. Please proceed.

Brian Downey -- Citigroup -- Analyst

Great, I had a question about the Delaware. I appreciate you taking the questions. Yes, I understand we announced some good Argentine well results of the Wolf Camp B and 3rd Bone Spring versus, the earlier Grizzly pad in Southwest being more focused on the Wolf Camp A. Just curios as you substitute the Buckskin patent for the Tinman and therefore inherently few return lines in Area 3 for 2019. Were there any of the results to-date have changed medium to longer term thinking of optimal zone development in the Block 4 area? I know you touched on some commentary on the Bone Springs, but anything additional would be helpful?

R. Scott Meyers -- Chief Financial Officer

Brian this is Scott. And I would say, the answer is no. The reason we switched out of the Tinman development -- or the Tinman completion is purely based on capital management. When we look at that area overall as we discussed the Windy Mountains we're still learning a tremendous amount about the area and it definitely excites us about where we're going with that area. It's such that it is lower GOR that does present some questions about when you add the artificial lift, those types of things, but we still have a tremendous a lot-amount of expectation there for that particular area and don't see it being any kind of problem. Just looking at it first in the queue in 2020 is what we're looking at today.

Brian Downey -- Citigroup -- Analyst

Got it helpful. And then I guess quick one on the Wattenberg. You mentioned that the potential to adjust timing of the frac holiday given you're ahead of schedule on the completions there, I know you also have some flexibility there with DUC counts and completions in 2020. But curious of that effect, the inherent 2020 cadence of production or activity, haven't given a ton of detail beyond the high level, that adjusted growth, but curios on that front?

Scott Reasoner -- Chief Operating Officer

I'll start with this and then Scott Meyers may jump in, when we look at the effort that our teams have put in up to this point, it's been terrific. We've been ahead of schedule, that's just then executing really cleanly out in the field. We see that continuing through the year at a fairly solid pace as you would expect that could cause us to lay down that frac crew a little bit earlier and that would bring some additional downtime at the end of the year. It really does begin to effect early 2020 in terms of productivity, but we've been modeling that all along in our expectations for 2019 and 2020. Those wells, that -- if you look at that frac hiatus that you have at the end of the year, it really ends up affecting 2020 the most, as we saw with our Delaware stoppage this past year and expect late this year as well, as we lay down the frac crew theirs too. So Scott, did you have other comments?

R. Scott Meyers -- Chief Financial Officer

No, I would just say that from a material standpoint our 2020 would not be significantly impacted just little bit of timing around the quarterly trends. But as Scott said we factored in a frac holiday in 2019 and what we already, so it's really in line with expectations and maybe just has to be down for an extra week or two.

Brian Downey -- Citigroup -- Analyst

Got it. Appreciate it.

Operator

Thank you. And our next question comes from Irene Haas with Imperial Capital. Please proceed.

Irene Haas -- Imperial Capital -- Analyst

Hello, so my question has to do with you mentioned earlier, that the share buyback will be done in two tranches and I guess, this one that it's going to be done on a more regular basis than rather opportunistic. Can you tell me, kind of what's the split between the two? I mean, $200 million is a very, very meaningful and could relate to -- could result to quite a decrease in share count?

Barton Brookman -- Chief Executive Officer

Yes, we still have some time to be reviewing it with our Board of Directors. We've laid out our plan and we're still finalizing. But I think you -- from a standpoint, it will probably be about half and half, it's what our thought is right now. We want to make sure we start the program, we get some dollar-cost averaging in with the buybacks, but also have a portion that we could, if we see a material move down for a short period of time due to oil prices or something like that, we could optimistically buying back at little effective rate. So I would say model with 50-50 for now, but we've more to come in that in the next couple of months as we get closer to beginning to execute the plan, which will be in the third quarter of this year.

Irene Haas -- Imperial Capital -- Analyst

Great. Thank you.

Operator

Thank you. And our next question comes from Gabe Daoud with Cowen & Company. Please proceed.

Gabriel Daoud, Jr. -- Cowen & Company -- Analyst

Hey, good morning, everyone. Maybe just a quick follow-up on the midstream sales. Obviously, nice to get that done and on the crude gathering, maybe just asking the question a little bit differently. But could you maybe remind us or just tell us what the percentage of the $150 million in invested capital and then total? What percentage of that is related to the crude gathering piece, if you could disclose it?

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Gabe, this is Lance. We haven't broken that out. We've spoken to the $150 million invested since the acquisition and that was as of the year end 2018. And of course, we've got some spending time this year as well, that I'll add to that. So we haven't broken that out specifically. But again, we're in the final stages of that negotiation and so that we anticipate that, that transaction will be announced here soon.

Gabriel Daoud, Jr. -- Cowen & Company -- Analyst

Okay great, thanks a lot. And then just a quick follow-up, I guess. Can you maybe talk about the trajectory for I guess, both volumes and capital throughout the rest of the year? I guess particularly as DCP's Plant 11 should come on here pretty soon.

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Yes, I would say from a volume perspective, we think that we'll have a stair step in the second quarter and another stair step in the third quarter. Fourth quarter being a smaller step is the completions activities in the Delaware slowdown. And I think from a capital perspective, you're going to see our second quarter capital being close a little bit less than it was in the first quarter and then material drops in the third and fourth quarter with our rig drop that we have scheduled in the Delaware and the frac holidays that we've mentioned both in Delaware and in the Wattenberg, with that lining us up toward that $840 million midpoint number.

Gabriel Daoud, Jr. -- Cowen & Company -- Analyst

Okay, great, that's very helpful. Thanks, everyone.

Operator

Thank you. (Operator Instructions) Our next question comes from Joe Beninati with Oppenheimer. Please proceed.

Joe Beninati -- Oppenheimer & Co. Inc. -- Analyst

Hi guys, thanks for taking my call this morning. I just had a quick question on the Delaware cost side, you guys have obviously done some good things, bringing your completion costs down. Do you see that percentage of using in basin sand going up over time or do you think where you guys are now that 50% is kind of a sweet spot for you?

Scott Reasoner -- Chief Operating Officer

So it's a really good question and it's something that we're constantly in the thought process of how do we continue to expand it because obviously there is cost savings associated with that. We've tested up to 75% sand -- in basin sand in the Delaware. It's still something that we're watching carefully. You're switching from 40-70 northern to 100 mesh in basin sand and not something we just want to make sure we're not seeing a degradation in the productivity of our wells. Obviously, we're pushing toward that as quick as we can. We realize other folks are using that, other of our peers are using 100% in basin. But at this point, we're just going about it cautiously and don't want to have a negative impact on our productivity of our wells.

Joe Beninati -- Oppenheimer & Co. Inc. -- Analyst

Okay, that's all from me. Thanks, again.

Scott Reasoner -- Chief Operating Officer

Thank you.

Operator

Thank you and with that, this concludes our Q&A session for today. I would like to turn the call back over to CEO, Bart Brookman for closing remarks.

Barton Brookman -- Chief Executive Officer

And thank you Tiffany and thank you to everybody for joining the call and your ongoing support and we'll be seeing a lot of you here in the near future.

Operator

Ladies and gentlemen. Thank you for your participation in today's conference. This concludes the program. You may now disconnect. Everyone have a great day.

Duration: 45 minutes

Call participants:

Michael Edwards -- Senior Director of Investor Relations

Barton Brookman -- Chief Executive Officer

R. Scott Meyers -- Chief Financial Officer

Scott Reasoner -- Chief Operating Officer

Lance Lauck -- Executive Vice President of Corporate Development and Strategy

Welles Fitzpatrick -- SunTrust Robinson Humphrey -- Analyst

Brian Downey -- Citigroup -- Analyst

Irene Haas -- Imperial Capital -- Analyst

Gabriel Daoud, Jr. -- Cowen & Company -- Analyst

Joe Beninati -- Oppenheimer & Co. Inc. -- Analyst

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