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As previously announced, we reduced our 2019 CapEx budget to approximately $95 million, which should allow us to drill uncomplete. Now, there has been some confusion that I've seen some of the analyst report that is drill and complete for net wells and complete one net DUC well in the Bakken and drilling complete 4.75 net wells and complete 1.9 DUC wells in the Delaware.

Now, you can do the math and look at the schedule that we're going to be talking about. You'll see that the Delaware is frontend loaded and the Bakken is back end loaded, which should allow us to report fairly steady production growth quarter-to-quarter without the usual spikes up and down. The timing of these well should allow at worst neutral cash flow each quarter and we plan to use the free cash flow to pay down debt.

The timing should also allow us to grow production low double-digit year-over-year using our published type curves which we continue to beat most of our wells. We remain flexible in our budget to allow appropriate reaction the commodity prices, current oil prices and vendor costs as they continue their current trend could allow us upsize our budget while still generating free cash flow.

Despite curtailments, delays and flaring in the Bakken caused by high differentials weather and processing capacity constraints and occasional flaring in the Delaware caused by frustrating plant outages, current operations are running smoothly. I'm just very glad that we shutdown our Raven Rig in the Bakken when we did because I hate to see the issues we had faced due to the horrendous cold weather up there this year.

Now, despite these excuses, which some has taken as a warning to reduce production in the first quarter, this is new information. Average production for January and February approximated 11,100 Boe per day which is up 6% over Q4. Now, the first half of March is little lower. We've had the combination of continued weather outages in North Dakota. And now of a sudden, severe weather in West Texas, which has given us electricity outages, which has lost a considerable amount of production.

Luckily, we have a number of initiatives under way, which I'll talk about for the second half of March, which hopefully will remediate these issues and allow us to report very good production in the first quarter. In the Delaware, we just started flow back this week on a two well Creosote Pad, which we now own 95.5% working interest in. We have a frac scheduled to start next week on a one well Hackberry Pad where we own a 75% working interest.

We're currently drilling at two well Woodberry Pad which being asked where is that, it's actually in section 3 offsetting our Caprito block and we own 100% of those two well. Now in completion of the drilling of the Woodberry Pad, the rig moves to a two well Creosote Pad where we also own a 100% working interest. And on completion of the Creosote Well, the Delaware budget is currently stated is done.

So, that gives us back to the Bakken which on a timely basis will start up activity on the Delaware slows down. Now, the weather delayed gas pipelines to our Raven Northeast Pad in the Bakken looks like is finally going to be in the service within the next two weeks. That will allow first gas sales from this pad which heretofore have been faired and allowed chokes to be bumped up to increase oil production.

The weather delayed work over to retrieve a piece of coil tubing in the Raven 12H which is a new well, started this week upon success and continuation of drill plug drill out, we will get additional production from that well. We plan to frac the Lillibridge DUC as soon as weather permits the spring, which should coincide with the Delaware slowdown. And we also expect to restart Raven Rig 1 on a six well Jore Extension Pad sometime this spring depending on whether. And any results from our value crystallization process which is just now getting kicked off in earnest but with a very pleasing amount of early interest.

And with that, I will ask for questions.

Questions and Answers:

Operator

Thank you. (Operator Instructions) And your first question comes from John Aschenbeck with Seaport Global. Your line is open.

John Aschenbeck -- Seaport Global -- Analyst

Good morning, Bob and Steve, and thank you for taking my questions.

Steven P. Harris -- Vice President, Chief Financial Officer

You bet.

John Aschenbeck -- Seaport Global -- Analyst

But my first one Bob, I was hoping you could walk us through a little bit more on just some moving parts of production or CapEx for the year. Your prepared remarks certainly help there, but just looking at it from a 30,000 foot view. What is the general quarterly progression of volumes in CapEx? Look like through the year, at least the first couple of quarters specifically just trying to get your comfort on liquidity right now at the Bakken sale which would certainly help, but just as continue status quo, just what does everything looks like from a 30,000 foot view? Thanks.

Robert L.G. Watson -- President and Chief Executive Officer

Well, the budget in the Delaware is I don't have it right in front of me.

William Krog -- Chief Accounting Officer

46

Steven P. Harris -- Vice President, Chief Financial Officer

46 million and that's going to be consumed roughly in the first half. The final existing budget item in the Delaware is fracking the Greasewood Pad. I might have misspoke a minute ago and said the Creosote Pad where the Creosote Pad on flow back as we speak and then in the two wells in our budget are Greasewood, so that should get up to about midyear, at which time we expect to be fracking for DUCs in the Bakken with the attendant production growth associated with them and start the Raven Rig 1 to drill a six well pad, which in our probability would get us to a point where we were don't to frac those wells until the spring of 2020.

So, I envision production basically flat for the next three quarters and then depending on when that Jore wells are completed either a spike up or continuation of flat. As far as liquidity goes, we fully expect to have a -- we already have our bank meetings. We fully expect to have an upward increase in our borrowing base by the end of this month. And certainly, we will let you know that. So, we have no concerns about liquidity issues, and we think the way we reschedule our budget, not only allows us to generate free cash flow, but allows us to have some sort of smooth growth pattern throughout the year rather than the soft tooth that we have experienced in the past.

John Aschenbeck -- Seaport Global -- Analyst

Okay, got it. That's great. Appreciate that. Then for my second one, I just was hoping you could discuss parent child degradation, which is topical these days growing as a topical discussion. You guys have certainly been one of the more conservative operators with regards to tests of that at your well spacing. But just curious as it pertains to your acreage, how many parent wells do you have on your acreage currently? And I guess what I'm really getting at Bob is, if you do in deep believe that your Delaware assets are worse or much more valuable in the hands of a larger operator. I'd imagine if you had less parent wells your asset could be relatively attractive. So can you just walk us through that? That with -- the color would be appreciated. Thanks.

Robert L.G. Watson -- President and Chief Executive Officer

You're always on top of things, John, and I appreciate it. As an engineer, I like to have all the data I can get, and the more data I can get the happier I'm. So, we're still evaluating the down spacing test that we did, but I can't tell you that the production results are trending toward an optimum spacing around 900 feet. So, that's why we continue to report our future net locations that we've been identified on 1,320 and 660 spacing. So on all probabilities, the actual numbers are going to be coming somewhere in between.

And as far as parent wells go depends on how close you want to cuddle up to them, the data that we have albeit it's a most small sample wet, we have one parent well and four offset to it. It would appear that a well is 1,320 feet away has zero degradation from a parent well that's been on production for a couple years where a well 660 feet has about 20% to 25% degradation. Those wells are still economic and in our scenario, so that doesn't mean you don't drill them. But there is probably an optimum distance in between wells, which I just spoke to maybe is around 900 feet.

So that being said, you can look at our presentation map and see how many wells we have drilled on each section and whether you call that two well pad -- one parent well or two parent wells. There is some indication that both zones in the Wolfcamp A are speaking to each other. So, if you have a well in A1 and A2, it's probably just basically one well, two wells producing the reserve associated with just one well. So, it would be difficult to say how many parent wells we have because of that relationship, we don't have any evidence at the bump springs is speaking to the upper Wolfcamp A.

So that would mean that third Bone Springs well would be a separate parent well, and we actually have no indication that the upper third Bone Springs is not communicating with the lower third Bone Springs that's a two well test that we have. So, it's a rather limited data set. So, it's going to be difficult to say how many true parent wells we have, but suffice to say we have a lot of locations to drill on 1,320 spacing even more on 900 foot spacing. So, I don't think there is a whole lot of degradation and value from the drilling that we've done. So far it's mainly been delineation improving up zones that we can now book is proven, although, we can't because we can't get to them within our five-year timeframe, but they are certainly there.

John Aschenbeck -- Seaport Global -- Analyst

Okay, awesome, that's great color. And you know what, just to maybe attack it from a different angle. And I'm not sure if you have it in front of you, but just how many wells in total both parent and children have you drilled on your acreage? I know you've only been active there for a couple years, so I'm sure I can go back and take up that number, but if you had -- have it handy that would be helpful. Thanks.

Robert L.G. Watson -- President and Chief Executive Officer

Yeah, we have 16 wells on production, we have 2 wells on flow back and we're fracking 1 well as starting next week. And then of course, we're drilling a two well pad as we speak. So, 16 on production, 2 on flow back, 1 fracking and two drilling.

John Aschenbeck -- Seaport Global -- Analyst

Okay, great, that's it for me. Thanks for the time, Bob.

Operator

Thank you. Your next question comes from Noel Parks with Coker Palmer. Your line is open.

Noel Parks -- Coker Palmer Institutional -- Analyst

Hi, good afternoon. How you doing?

Robert L.G. Watson -- President and Chief Executive Officer

Good, Noel. How are you doing?

Noel Parks -- Coker Palmer Institutional -- Analyst

Real good. Thanks. So, yeah, just a few things. I think it was last quarter you were talking about again on the parent-child issue, preloading parent wells before fracking children, have you done anymore of that?

Robert L.G. Watson -- President and Chief Executive Officer

We have not because we haven't drilled any more child wells. It's still under study whether that really has a significant impact or not. We are getting data from offset operators that we have data swap agreements with. And hopefully between our data and their data, we'll will be able to come to some conclusion. But with our current budget in the Delaware, we have no child wells planned for the remainder of this year. Now that could change, if commodity prices tell us to drill more wells and keep our rig going out there. But even on an expanded plan, I don't see us having any real child wells to drill for the next couple of years really.

Noel Parks -- Coker Palmer Institutional -- Analyst

Got you. And just speaking of your rig in the Delaware. I'm sorry, were you going to add something else?

Robert L.G. Watson -- President and Chief Executive Officer

No.

Noel Parks -- Coker Palmer Institutional -- Analyst

Okay. Sorry. My next question just was as far as your rig in the Delaware, while what sort of -- do you have that on a contract or commitment?

Robert L.G. Watson -- President and Chief Executive Officer

Yeah. We're committed for basically the rest of our program that's in our budget and then that's it.

Noel Parks -- Coker Palmer Institutional -- Analyst

Okay. Got you. And speaking of data from offset authors, anymore thoughts on the second Three Forks up in the Bakken?

Robert L.G. Watson -- President and Chief Executive Officer

That's a good question. And we've actually discussed that quite a bit in the last five days. The best data we have happens to be wells that are directly offsetting us that we actually have a working interest in. There are six wells in the second bench of the Three Forks operated by Continental that are Wiley and Bailey units. We have a small working interest, but what means we get all the data. And those wells are performing very well. So I think the seasoned operators up there are accounting the second bench as a true target, but people outside the play are not giving anybody credit for it.

So we looked at -- and when we did our reserve report this year, we had to lay out a five-year plan to get PUDs booked for the SEC, and because we don't have all the data on the second bench Three Forks that we would like to have, yet, we have very good data in the Delaware, we kind of swapped out those wells move them from the PUD to PRUD probable undeveloped, and replaced it with Delaware wells that we have ample data to give us comfort that, that makes a drilling program worthwhile going forward.

So we're going to keep watching it and study in it. And watching those Continental wells and talking to our geologists that has worked and worked and worked at area. There is no geologic difference between our leases and the Continental leases. So I guess the big question is, how much is the second bench communicating with the first bench. Now the fact that the Continental well second bench wells are better than their originally drilled first bench wells would tell you, maybe not a lot or maybe it's just improved completion efficiency that's causing better wells. But hopefully, time will tell and by the time we get around to our second bench locations, we'll have enough knowledge to go one way or the other.

Noel Parks -- Coker Palmer Institutional -- Analyst

Okay, great. And just a last, but sort of a bigger picture question. Of course you're looking at -- or you're in marketing the Bakken. And I was just thinking as you look ahead and suppose that we spend an extended time and kind of this $50 a barrel type range. As far as, I guess, where capital should go in your basis and then in the industry, we've kind of turned the corner from that time a couple of years ago when private equity money was funding a lot of people to go out trying to concepts prove them up with the acreage and that also slowed down in a big way last year to the point where you even saw some of the exits, people are making actually being for equity instead. I just wondered what your thoughts were. If you look forward to maybe where you monetize some of your assets and you're in a position again with some money to spend just how you think of, I don't know if you call exploratory or kind of a step-out business model, like that given the different basins, you've been in to date.

Robert L.G. Watson -- President and Chief Executive Officer

Well, I think you can look at our corporate presentation and see that we're generating considerably better economics in the Bakken and we are in the Delaware. So if I all my wishes come true, I would wish that we would have more acreage in the Bakken similar to what we have. That's probably not a realistic wish, because everybody else wants that acreage and no one is going to give it up. So I think if we do something with the Bakken to where it's no longer us and we have extremely clean balance sheet with a whole bunch of cash to the financing -- the Raven Rig down in the Delaware until we get free cash flow. I think we've got certainly enough upside running room in the Delaware, that would be have to be where we would go. If I was starting up a new company, would that be the case, maybe not, because the cost of entry is so high. But it's still a pretty good place to go and it's kind of unique and it has so many landing zones that people are just now getting to and we don't know what the ultimate number of locations is going to be because of that. So it's an interesting area and I'm hopeful that when we have the experience in the Delaware that we've garnered in the Bakken and use that experience to drive cost down that we can get equivalent economics in the Delaware that we've achieved in the Bakken.

Noel Parks -- Coker Palmer Institutional -- Analyst

Great. Thanks a lot.

Robert L.G. Watson -- President and Chief Executive Officer

Thank you, Noel.

Operator

Thank you. Your next question comes from Eric Engel with Stifel. Your line is open.

Eric Engel -- Stifel -- Analyst

Hey, good afternoon guys. Just hoping to get a little more color on the level of interest you're getting in the Williston asset sale? And then what type of buyer, the sale is attracting?

Robert L.G. Watson -- President and Chief Executive Officer

Well, Eric, that's a -- all we can say because it's very competitive situation is that we had a very pleasing amount of interest to-date and that it varies from the very large to the small unknown. And it varies from public companies, to private companies, to private equity backed companies. It's the whole gamut. And that's very pleasing to us because we don't know which one is going to offer the best deal for us, if anybody does. So, we're just glad to have the interest that we have in there and we're gaining more and more every day. The data room really just went live this week at least where the process is just now getting started. Now, I don't want to be sound cavalier about it, and as soon as we have something a little bit more concrete that we can talk about, we'll certainly be talking about with you.

Eric Engel -- Stifel -- Analyst

Okay. That's understandable. And then if the sale goes through, how do you plan to prioritize the proceeds, or what do you plan to do with them?

Robert L.G. Watson -- President and Chief Executive Officer

Well, it would be in this order, pay off debt completely, even though we say pay down debt, now the payoff debt completely. Then fund our Raven Rig 1 to move to the Delaware and can start continuous program with enough cash to where we don't have to borrow any more money to get the new Delaware program up to a free cash flow basis and then continue to operate on a free cash flow basis thereafter. There's anything left over, I'm hopeful that our board would let us go in and start buying back stock.

Operator

(Operator instructions) Your next question comes from Ron Mills with Johnson Rice. Your line is open.

Ron Mills -- Johnson Rice -- Analyst

Good afternoon, Bob. Just one last questions is that, since the data room just went live last week, any sense in terms of when the Petrie guys or how long they were expecting the process to take? Is this something that could be as early as a second quarter event or I'm just trying to get a framework -- more broad framework of that?

Robert L.G. Watson -- President and Chief Executive Officer

All of that depends on whether we have a number that we're OK executing on, it could come down to where PP says well, the market says, keep the asset and just cash cow it. But if we do have something we might execute on, we expect it to be mid second quarter mid -- no, no actually -- mid-April timeframe, so start at the second quarter.

Ron Mills -- Johnson Rice -- Analyst

Okay, great. Thanks. And then, as we look at Delaware and well performance when you look across the zone from the Bone Springs through the A1 to A2 and B. As you continue to add more recent wells, should we be thinking that what results from like the A2 and the B likely potentially continue to improve like they did in the third Bone in the Wolfcamp A as you had a couple more wells of more recent completion vintage brought on? Or how should we think about the upcoming Delaware completions?

Robert L.G. Watson -- President and Chief Executive Officer

Hopefully, they'll keep getting better. We continue to tweak our frac design the -- we are going to test the Wolfcamp B in a Greasewood well coming up. So we're not sure about the rather poor performance of our first Wolfcamp B well whether that was mechanical or reservoir. Looking at the rocks, we tend to think -- we had a number of mechanical issues drilling that well and we had two frac it on that well. So, we're hopeful that that caused the underperformance as opposed to rocks. So, we will give a try again. It looks like the A2 is perhaps not as good as A1, but they are still pretty good.

Both of them are still beating our type curve. The A1 keeps beating it a little bit more. The third Bone Spring is a very pleasant surprise, but we have a limited data set on that. So even though we got 16 wells on production, we're in five different zones. So we don't have a big universe of data in anyone one zone. So, I guess, we have to hope that they are going to continue to improve. I know our Bakken results over nine years improved every generation of frac design and some of them improved considerably. And I'm hopeful that will be the case in the Delaware as well.

Ron Mills -- Johnson Rice -- Analyst

And what do you think your average lateral link will be this year? You still stick in more to 5,000 to 6,000 foot laterals, and any commentary on what you expect from well cost as we go forward given the current environment?

Robert L.G. Watson -- President and Chief Executive Officer

We did that study that we announced at your conference last September, which opened some people's eyes, and we still hold by those results that was a 450 well study. So, that's a pretty good universe of data. We are in the process now that our year end reserve report finished. Our engineering groups in the process of updating that study to see, if it changed any. But those are you are out there that are not familiar with that study. We determined that to the best of the data will allow us to say that short laterals have a higher rate of return than long laterals for a whole number of reasons that we don't really need to go into right now unless you want to. And so, our thought process is we will continue with 5,000 foot laterals until the data says, you need to be going long, if it ever does.

Ron Mills -- Johnson Rice -- Analyst

Okay, on the well cost side.

Robert L.G. Watson -- President and Chief Executive Officer

We've actually had a reduction. I think our (inaudible) were about 7.6 million for a 5,000 foot lateral and that's a 26, 27 stage frac. So, they come in a little bit. One is from just learning curve efficiency and two pressures pumping cost have come in considerably obviously using in basin sand that saves money. So, hopefully, our experience in the Delaware will track our experience in the Bakken where we've driven cost down over time. And our last 10 or 12 wells in the Bakken were all between 6.5 and 6.7 million, incredibly consistent, and that's what we're trying to achieve in the Delaware.

Ron Mills -- Johnson Rice -- Analyst

Okay, great. I'll let someone else jump in. Thanks, Bob.

Robert L.G. Watson -- President and Chief Executive Officer

Thanks, Ron.

Operator

Thank you. I'm showing no further questions at this time. I would now like to turn the call back to Steven Harris for closing remarks.

Steven P. Harris -- Vice President, Chief Financial Officer

Great, we appreciate your participation today in the Abraxas earnings conference call. As I mentioned at the start, a webcast replay will be available on our website as well as transcript which will be posted in approximately 24 hours. So, thanks everybody and hope you will have a good day.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you all may disconnect. Everyone have a wonderful day.

Duration: 30 minutes

Call participants:

Steven P. Harris -- Vice President, Chief Financial Officer

Robert L.G. Watson -- President and Chief Executive Officer

John Aschenbeck -- Seaport Global -- Analyst

William Krog -- Chief Accounting Officer

Noel Parks -- Coker Palmer Institutional -- Analyst

Eric Engel -- Stifel -- Analyst

Ron Mills -- Johnson Rice -- Analyst

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