Good morning. My name is Andrea and I will be your conference facilitator today. Welcome everyone to the Whiting Petroleum Corporation First Quarter 2019 Financial and Operating Results Conference Call. The call will be limited to 45 minutes including the question-and-answer session. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. [Operator Instructions] I will now turn the call over to Eric Hagen, Whiting's Senior Vice President of Investor Relations. Please go ahead.

Thank you, Andrea. Good morning and welcome to Whiting Petroleum Corporation's first quarter 2019 earnings conference call. On the call with me is our Chairman, President and Chief Executive Officer, Brad Holly; Chief Financial Officer, Mike Stevens; Chief Operating Officer, Chip Rimer; and Chief Strategy Officer, Tim Sulser. During this call, we'll review our results for the first quarter 2019. The conference call is being recorded and will also be available on our website at www.whiting.com under the Investor Relations section. We also posted an updated corporate presentation to our website earlier this morning. Please note that our remarks and answers to questions include forward-looking statements that are subject to risks that could cause actual results to differ materially from those in the forward-looking statements. Additional information concerning these risks is set forth on slide number 2 in our earnings release. And with that, I'll turn the call over to our Chairman, President, and Chief Executive Officer Brad Holly.

Thank you, Eric. I would like to start off by thanking the Whiting team for their hard work during the quarter. It was a particularly severe winter in our operating areas with temperatures below minus 30 degrees for extended periods in North Dakota and the bomb cyclone weather events in Colorado. Our teams in the field proved they are second to none and did a great job keeping production online. The overall result was a solid quarter on the production side. This positions us to deliver growth that accelerates in the second half of the year while staying on budget. Taking a broader view, we believe that our strategy of maintaining discipline through the cycle and not chasing the commodity price is industry-leading. This strategy maximizes free cash flow by maintaining a highly efficient level-loaded program. Whiting is also well-positioned to weather pricing downturns as an industry leader in capital efficiency with a prudent hedging strategy. Recent volatility only heightens our commitment to pursuing a disciplined returns-focused strategy. In taking this role at Whiting, I had a hypothesis that large oil fields get larger over time and by using and developing technology more, more oil could be economically recovered. When I got to Whiting, I found others that believe the same thing. Our recent well results in many different parts of the Williston Basin proved this hypothesis to be correct and the well results are stunning. What I did not expect is that we could have a positive effect on parent wells. But we are in fact seeing some impressive uplifts on existing production rates on older wells that we believe are more than just flush production. Whiting is leading the way in driving value and returns from the prolific Bakken and Three Forks reservoirs. The Whiting Way is built on a foundation of resilience, respect for fellow workers, effective communication, and business excellence. I've never been more proud of a team and the values they uphold. Our people are engaged, embrace change, and remain committed to the highest standards. With that, I will hand things off to Mike Stevens to review our financial results for the quarter and discuss our forward outlook.

Thanks, Brad. Our Williston Basin volumes continued to grow during the quarter. It seems to minimize declines on the oil side despite a light POP schedule and took advantage of a slowdown in the pace of activity to increase our gas capture rate. Looking forward, we project some growth in the second quarter even though our new wells put on production are back-end loaded. This is followed by strong growth in the second half of the year. The oil mix should improve and normalize consistent with our original guidance as we bring on new wells. First quarter operated CapEx came in a little lighter than expected. Looking forward, we project relatively flat CapEx in Q2 followed by lower quarterly rates in Q3 and Q4 as we drop a rig to manage our DUC count and shift to putting wells on production. Echoing what Brad said, our strategy is designed to benefit from commodity price fluctuations. We took advantage of the recent oil price increase to put on additional hedges in the second half of 2019 and the first half of 2020 locking in favorable pricing. We are 57% hedged for the balance of 2019, at strong prices with a mix of swaps and collars. We are doing this to provide a clear path to projected free cash flow going forward, so we can meet our goal of leading the mid-cap E&P space in free cash generation. On the cost guidance side, we have tweaked some assumptions primarily to reflect first quarter results in our full year forecasts. On a net basis, our cost guidance remains similar to our original assumptions. Bakken differentials are up slightly and production and ad valorem taxes are down to reflect first quarter results. DD&A is up due to lower SEC reserve pricing. To summarize, the first quarter had some hangover from the end of last year on differentials and additionally, we experienced volatile gas and NGL pricing. However, the environment has normalized and we are back on track with our original projections. I'll hand off to Chip Rimer to discuss some highlights from operations.

Thank you, Mike. I'm going to address projects that we highlighted in our corporate presentation that was updated earlier this morning. One thing that sets Whiting apart is we don't just focus on early-time results. We give long-dated hard data on key projects. Two projects that we have provided an update this morning are good examples of our leadership in expanding the Bakken core. In the Cassandra area, we are now over 100 days of production on our Bakken and Three Forks wells. The wells continue to outperform the peers by a wide margin. The wells were completed on similar proppants as competitor wells. This illustrates the effectiveness of Whiting's multidisciplinary completion model in driving leading capital efficiency. Also in the Northern area, we recently completed our Ray Gas Plant. This was – this will support increased activity in the Polar area in 2019 and future development in Cassandra. In the Southern Hidden Bench, our Stenehjem wells now have over 80 days of production and continue to outperform the parent wells by over 100%. At our Foreman Butte, we are moving ahead aggressively with the delineation plan. We have drilled all 17 wells in our 2019 program. Completions have commenced and we expect to have enough data to provide results in the third quarter. As a reminder, we acquired this acreage at an attractive price of under $1,500 per acre last year. I want to end by highlighting what our Eastern team has accomplished in Sanish and the Pronghorn areas. The results across multiple projects are exceptional. Infill wells are outperforming parents by 100% to 200% in Sanish. Also in contrast to other basins parent wells are experiencing a sustained uplift in productions. Once again, I believe this reflects our unique ability to customize the completions for each unit. In any cases, we were able to effectively re-stimulate the parent well, capture new reserves, while putting Generation four or five completions on the new well. We provide a lot of new detail on our operation pages between 15 and 24 on our corporate presentations. Finally, I want to end by echoing Brad in thanking our team both in the field and the corporate headquarters. You have set us up for a very successful 2019 as we move forward with growth and free cash flow mode. Thank you. Operator, please open the conference call for Q&A.

We will now begin the question-and-answer session. [Operator Instructions] And our first question comes from Drew Venker of Morgan Stanley. Please go ahead.

Good morning, everyone. I was hoping you can talk a little bit about how you're thinking about the program in a higher price environment thinking a little bit longer term. You stated before your priorities for use of cash would be to reduce debt at higher prices here obviously achieving that sooner. So, how are you thinking about more like 2020 and beyond activity levels and tighter free cash flow?

Yeah. Drew, this is Brad. We are staying the course on that. We have certainly enjoyed the uptick in price. Late in the quarter recently here as Mike mentioned, we've taken advantage of that and then actively hedging recently. And we're still really adamant about our program to take every free cash flow dollar, we can and to pay down our debt and to get our debt levels where we have stated. And then we continue to look for high- inventory, high-quality Tier 1 inventory that would compete today in our portfolio.

Thanks for the color, Brad. So as you think about the development program over the next couple of years, you obviously just finished that gas plant expansion. How much runway do you think that gives you in that area? And do you think you have other areas where you need to expand gas processing or gathering facilities over the next couple of years?

Yes, Drew. Thanks for the question. We really like the 11% growth this year overall volumes in the Williston and even 15% on the oil side. And so we believe that our future portfolio in the near term gives us the opportunity to have those kind of growth rates while also throwing off substantial free cash flow. And our plan forward is to keep that running. I'll let Chip comment a little bit on the actual gathering systems out there and if there's anything else he would do.

Yes. I don't think there's much else to do Brad looking forward to it. If we look at the Cassandra, we're set up there for development of Cassandra with Ray Gas Plant and we'll have capacity going out of the basin. So we're in good shape.

Just one follow-up then on the bolt-ons, you guys have talked about as being interesting to you all. The results outside of the core have been very strong in the Bakken recently from you and to me it appears. Does that change the appeal at all of doing those bolt-ons or I guess strengthen the appeal of doing bolt-ons? Or are you guys kind of sticking to the plan of, we will definitely generate free cash flow and that's priority number one and M&A would be secondary?

Yes. I think I would -- this is Tim Sulser. And I would echo what Brad said. It's prioritize around paying down debt and acquisitions that compete in our portfolio.

Thanks.

Drew as you pointed out the highlights of having good success around us have also upgraded our acreage as well. And so we have more inventory today in our own acreage than we had a year ago.

Understood, thank you.

Our next question comes from Neal Dingmann of SunTrust. Please go ahead.

Good morning all. Brad, it seems like there's some investor concern just on CapEx. Could you walk through again how you sort of see that unfolding for the remainder of the year? And I know you've got sort of a number out there for the entire year. I'm just wondering if things like if non-op runs a little bit more or different things, but just your thoughts on making sure you stay within that overall guided range or just if you could talk about how CapEx might sort of trend for the remainder of the year?

Yes, Neal. Appreciate the question. Internally, we're right on our budget. We're right on our forecasts for both capital and production. This is where we thought we would be. We had expected to spend more money in the first and second quarters, so the $220 million is right where we thought it would be getting infrastructure in place. And we are committed to the $820 million long-term. So we did spend more non-op than we had anticipated, but that's for us to manage inside of our portfolio. So we will -- we're taking a critical eye of every non-op proposal. And our commitment is to put our money to work in the highest investment options that we have. And so the non-op competes with our operated production program and we will manage accordingly to come in on our CapEx budget.

Makes sense. And then just lastly, you continue to have just a ton of acreage I think over 470,000 acres. Your thoughts if the market's not going to reward you just value for that so your thoughts about, what you think about selling down some of the stuff that you deem maybe the least economic. Or I'm just wondering if there's any way to bring forward some of the economies given if you're not being reflected in the stock?

I think my initial response to that is Neal as we've been pleasantly surprised at the results in the fringe areas. I mean we're seeing core-like results in areas that were non-core. And the positive effects that we've had -- and Kelly Eisele that runs our Eastern Williston Basin organization, she is telling me that we have not pumped a Gen 4 or Gen 5 completion in her area yet that does not have a positive impact on the parents around that. And so we're still learning a lot about the basin. And I think we feel like our acreage holds tremendous opportunities in the right hands to develop it. And so that's how we're looking at it today is there's more value there.

Okay. Look forward to all the activity. Thanks Brad.

Thanks, Neal.

Our next question comes from John Freeman of Raymond James. Please go ahead.

Hey, good morning, guys. This is actually Graham Price on for John Freeman. Just real quick following up on the earlier question on CapEx, it looked like non-D&C CapEx was slightly lower this quarter. So just wondering how you see that progressing through the remainder of the year.

Yeah. The CapEx budget at $820 million like, Brad said is going to be not overspent. That is our number. That's where we're heading towards. So non-D&C right now, we spent a little bit on facilities a little less than we thought. And we didn't spend much on land. We spent a little bit on capitalized workovers. So again, we're just going to kind of watch where everything flows. Nothing set in stone here, but the only thing that's set in stone is the $820 million itself. So we'll watch all these other categories come forward. We'll probably end up a little under on facilities. Not sure where we'll end up on land right now depends on the opportunities that we get. But it could be we under-spend that and we get better opportunities in the non-op arena. We'll see where it plays out.

Okay. Perfect. Thanks for that. And then just quickly for my follow-up, I saw that your spud-to-TD times fell below nine days this past quarter. It’s really excellent work. Just wondering how many more improvements you see there over time and maybe what you see driving those.

Graham thanks for noticing that. And we're very, very proud of our drilling organization. They've done some amazing things this quarter. And I'll let Chip kind of walk you through some of that.

Yeah. Graham, thank you very much. Our drilling group continues to set records. They set several records this last third quarter on drilling 400 foot per hour on a lateral. I think it could be a record for the basin potentially. So they do a great job. They continue to find ways to keep the bit on bottom and keep on drilling. So they challenge us every day. They come up with new ideas. I love the way they think. And so we continue to -- I'm not sure where the end is right? It can't be zero, but it's going to continue to head that direction.

All right, perfect. Thank you, guys.

Our next question comes from Tim Rezvan of Oppenheimer. Please go ahead.

Good morning, folks. And thanks for taking my question. I'd like to start on, I think what was the biggest surprise in the print which was the NGL pricing, you reported on February 26. Can you talk about what changed between that earnings date and the end of the quarter? Because it appears that a lot of people were caught by surprise by the real weakness on the NGL side.

Yeah. This is Mike. I'll work through that with you. Let's just stop -- start from kind of a top level in that, our NGL price is generally driven in large part by what propane's doing. That's a good percentage of our NGLs. And then, the U.S. propane pricing as a percentage of WTI has been dropping. Probably you all know that our supply has been outpacing demand. In the Bakken itself, there's issues there as far as getting the NGLs out of the basin. Pipeline capacity is pretty full, so we're relying on higher-cost rail and truck. And that's definitely decreased the netbacks. So for these reasons, we did expect some pullback in our NGL price. The unexpected part or what happened since February is that we did have to adjust our fourth quarter pricing. And when we did that in the first quarter, it brought our first quarter pricing down. So our true price in Q1 was probably closer to $0.30 a gallon, $12 a BOE. But of course the pricing impact lowered our reported number. Looking forward, I think we'll probably be similar to that somewhere around $0.30 a gallon. That's about 25% of realized oil price. It's a little lighter than historic, but towards the end of the year we're going to have the new Elk Creek Pipeline coming on. And I think our pricing in Q4 and beyond should work its way back to 30% to 40% of realized oil price, which is about $20 a BOE.

Okay, okay. So that $0.30, a gallon number is -- when you said about like a normalized price that's sort of where you sort of see things into Elk Creek?

That's first three quarters of the year.

Okay, okay. I appreciate the details on that. And then, my follow-up looking at your POP schedule for the year, the heaviest quarter is 2Q. It's about 36% of your POPs for the year. I think we all know that when you have a winter snow in North Dakota, you get spring floods. So can you talk about how you've risked that number kind of what confidence you have, as you could be looking at a pretty soggy spring up in North Dakota?

Yeah. We always put a little risk in there. But what we're looking at is a lot of those POPs are back half of the year or back half of the quarter when you look at that. So when you look at that, you're probably going to have better conditions. So I don't think we have a huge risk at this point, but we do risk some of it.

Okay. I will leave it there. Thanks folks.

Our next question comes from Mike Kelly of Seaport Global. Please go ahead.

Thank you. Good morning, guys. I was hoping you could frame the benefit of this kind of parent well uplift phenomenon that you're seeing. And maybe if we could just kind of look at that from what this could potentially do to EURs maybe as a combined child well plus the added benefit here from the incremental production you'd see from the parent well? Or maybe from a returns perspective, just take a 50% IRR up to potentially 60% or 70%. Just so looking at these slides, I mean it's pretty amazing to see the uplift on Slide 20 for example. But if you could just frame just what the ultimate benefit could look like? Thanks.

Yes. Mike, thanks for the question and thanks for pointing that out. Slide 20 really shows there's a typical Bakken well, that's formed for five years and it's on the definite trend and it's made over 200,000 barrels of oil. And we go in and complete three offsets and the offsets are 250% better than the original well. And that's after 180 days. Again to Chip's points on the opening we're not basing this on 30-day IPs. I mean this is substantial production and we're seeing the parent just take off. This is one of the better examples on Slide 20 where we show a couple of others in the packet. So we're seeing different performance. It's not all the same. It's variable how it's hitting the parent wells. But I think Mike what it highlights is that the original Gen 1 and Gen 2 completions were very poorly done in the space and were not contacting enough of the rock around it. And so the newer Gen 4, Gen 5 completions are very efficient or actually touching rock that was never touched before. And so we do believe it is incremental production. And the rate of return on the parent wells is infinite. And -- but if you tuck that on to the economics of the investment dollars that we're spending, it's significant. I mean we think it's a 10% to 20% uplift probably in the IRR right now. But we're still -- it's early times and we're watching all that. But we're extremely excited about what we're seeing.

Okay. Appreciate that color. That’s it for me. Thanks guys.

Our next question comes from Jeffrey Campbell of Tuohy Brothers Investment Research. Please go ahead.

Good morning. First I wanted to ask Slide 18 noted that one Pod 8 goal was to derisk Three Forks in the Sanish Field. Just wondering could you add a little color on what derisking meant in this context and how it's been affected by the very strong Pod 8 results?

So the Three Forks is not consistent across all of the areas. So what we're trying to do was derisk some of that area. And so that's our process. We have Bakkens and Three Forks. And so -- but you can see -- look at the uplift that we had over to Brad's point and literally 233% on the Three Forks and the parent is going up. So as we go through this process we have additional derisking going on this year, but it's really looking very positive.

Okay, thank you. And the press release mentioned a large decline of Redtail production because of freeze-offs during the winter. I was just wondering if you could update us on what the current situation is in Redtail?

Yes. We -- most of the production is back online. We just have a little bit down at this point but everything is going very well and we should be back up to what we our budget is forecast is in Redtail.

Okay, great. Thank you.

Our next question comes from Leo Mariani of KeyBanc. Please go ahead.

Just wanted to get a little more clarity on an earlier comment, you guys spoke about having some Foreman Butte results later this year. Would you expect to have those with the second quarter earnings report or the third quarter earnings report?

Yes. This is Chip. Thanks for the question. Yes we've drilled all 17 wells. So they're all completely drilled and we're in the completion mode right now. We're actually going to be poping some wells very soon here. So we anticipate the third quarter to be the -- where you'll see the early results on those wells. We are doing some delineation across the entire acreage there and we're looking for what the typical spacing should be per zone? That's what we're doing right now.

Okay. So I guess just to clarify is that going to be in conjunction with the second quarter earnings call which takes place during the third quarter or that would be the third quarter earnings call in November to say?

November.

Yes. I think it would be more in the third earnings call Leo.

Okay, just want to clarify that. And I guess just wanted to see if there was any update on some of the activity you guys were doing in the Wildhorse area?

Wildrose?

Yes, Wildrose earnings.

Yes. It's early-time results. I mean, we're better than the original wells, but we didn't continue to evaluate those performance.

Okay. And in the Bakken, you guys also talk about some better gas capture in the first quarter here based on your production a bit. Can you talk a little bit about the dynamics around that? Do you expect that to kind of be sustainable throughout the year? I know you've got those -- the Ray Gas Plant coming on, which will benefit some of the second half production. Just trying to get a sense of whether or not your gas capture percentage should trend up throughout the rest of the year.

Yes. Let's just say pretty flat for the rest of the year what we're seeing right now.

Yes. If you recall Leo, it's Eric. We had issues with gas capture in the fourth quarter. And we basically managed to reverse those and capture some of that gas into the first quarter and now we're at more normalized levels. I'd say a simple way to think about it.

Okay. That's helpful. And I guess just on oil dips, I think you guys mentioned, there was a little kind of lingering issue from 4Q into sort of January here. But how do you expect oil dips to play out the rest of the year?

Yes. The guidance was updated mostly because of what happened in Q1. Really think we should be somewhere around $5 to $5.50 all in. Remember that that includes -- well in the first quarter, it's $1.71 for the Redtail deficiency payments. As we go forward, those increased to about $2. So the Bakken dip looks like it's going to hold strong in the $3 to $3.25 range. It's been a little better than that in March and April, and it's fallen back a little in May, but in those ranges. So that's what we're seeing so far. I think it should hold though.

Okay. Great color. Thank you.

Our next question comes from David Deckelbaum of Cowen. Please go ahead.

Good morning guys. Thanks for taking my questions. Brad, just curious as you look across the teams that you now have divided up. Given some of the outperformance with that you've seen with some of the Gen 5 completions or some of the infill activity in Sanish what -- which area do you think would sort of experience an increased allocation in capital relative to others going into 2020?

Yes. That's a great question, David. And that's something we really like about the asset teams, as they've all raised their game. And we're seeing better performance in the North, in the South, in the East. And we have a very competitive capital allocation process. And so our point is, they're doing their very best work, and we're going to roll it out for the company, and we're going to invest our dollars in very best investment opportunities we have as an organization. And so that'll be a fun process that we'll go through in the third quarter of this year and that we'll come at 2020 budget. But as you can see from our investor pack, we're seeing some phenomenal results in multiple areas. And we'll continue to watch those and make sure that it's not flush production and it's actually sustained increases. And we'll make this an economic value-based decision on where our best opportunities lie.

I would also say I love the ways our teams share lessons learned and growing across the board. So it's competitive, but they're sharing ideas.

Appreciate that. Just also curious, I guess, with -- you talked about the capital budget, and how you're going to stay and do that this year? I guess, should we also think about your calendar of well POPs as being fixed? Or is that inflexed right now?

Really, David, I would think about it being pretty close. But again to Mike's point, we're going to manage it. And so we've got more non-op spending and most of those wells frankly are in the heart of Sanish, and they're excellent economics, and we want to participate. And so we will adjust our activity accordingly to make sure that we deliver on our capital budget and on our production budget.

I appreciate that. And then -- and just one little small one if I might. You talked about getting back to sort of your normal run rate of oil mix, which is intuitive as you put more wells online. Just given, I guess, second quarter you kind of guided to some sequential growth, but your POPs are kind of back-end weighted. Should we be thinking that mix looks similar to this quarter, and then it just kind of trends back up to that higher 60s in the back half of the year?

That's probably a fair statement. We're hoping it improves a little bit but you want to be conservative, you can put it where it is here in the first quarter. But by the second half of the year, we should be rolling back up to where we expected to be.

Thank you, guys.

Our next question comes from Noel Parks of Coker & Palmer Institutional. Please go ahead.

Good morning.

Good morning Noel.

Following-up on something that you mentioned before you were saying that as an example in the Eastern region, you were just seeing consistent improvement in parent wells from the Gen 4 and 5 completion. And I'm wondering where in your footprint, do you still have the most room to maneuver or room to grow in terms of applying updated completions? I guess I was wondering in particular about Southern region Lower Three Forks even whether geo-steering improvements might bring more of that into play.

Yes Noel. Good question. I think the way we're looking at it is what Kelly's doing in the East region as infill work. So, Sanish was fully -- everybody thought was fully developed at one time and she's going back in to do an infill process. How it's changing is when we have success in places like Cassandra, it's causing Charles to work with Kelly and understand what we're learning in Sanish and it's changing our initial development in places like Cassandra. And so what an opportunity we have where we only have one well per section and we're redesigning that development program across our acreage based on what we're learning from our oldest most mature asset.

Great. And sorry I'm just also wondering as I said the South and the Lower Three Forks. But for my follow-up I wanted to just check we've seen some non-op sale activity in the basin. And I was just wondering if it does turn out that there's consolidation going on or -- and will continue in those sort of smaller interest ownership packages, do you have any significant opportunity there in terms of buying out non-op interest? And would any of that be enough to move the needle on returns? Anything that's going to weigh?

Yes. Noel sorry I missed your first Three Forks question. I'll let Chip address that and then Tim will comment on that.

Yes. Noel as we go -- we've picked up the latest -- as I said before we have these completions. We're using the five gen. So, there's real excitement out there onto what we can do and a lot over there. So, huge potential over there. We have our Stenehjem wells that we were down there. Also that we put a 4.5 kind of gen completion on those things. So, you're seeing opportunity in the Southern area. So, I think there's a lot of excitement there's a lot of runway. I'll hand it over to Tim on the other question.

Great.

Yes. Noel as it relates to acquiring additional acreage we're seeing good results. We'll certainly continue to go after that acreage as it continues to add quality inventory to our portfolio. I think from a big picture perspective that I think everybody needs to really appreciate is those original wells in Sanish that was cutting-edge completion technology at the time. And what's so great about our industry is our ability to innovate and really continue to grow returns over time right, especially in these lower price environments. That's what's really exciting about it and really makes it such as a long-term exciting basin.

Great. Thanks a lot.

Our next question comes from Paul Grigel of Macquarie Capital. Please go ahead.

Hi, good morning guys. On the Bakken halo testing you talked about 2018 over 2017 down in Pronghorn and the improvement that you've seen. Could you provide some detail on what's within the 2019 program for additional testing either Pronghorn or others of the Bakken halo as you look to increase inventory on an organic basis?

Yes. Sure Paul. We have been working out in Montana some. We've drilled a couple of wells that we call the Iverson Bros out there testing that. And then a big part of it is the 17 wells across the 55,000 acres we acquired. And so those 17 were specifically designed to really test the Southern part of our acreage. And so we're stepping up kind of in both of those areas in 2019 to try to prove up for 2020 program.

Okay, great. And then I guess one point of clarification maybe. Mike, I just want to make sure, kind of, it's crystal clear. For the $820 million of CapEx there's obviously a number of key areas underneath that non-op/operated infrastructure spending elements. You guys are trending lower on your operated and continuing to make progress there. Should we view that holistically within the $820 million? Or in terms of managing the non-op, is that managed to the specific non-op allocation, even if operated does trend ultimately at the end? Just trying to understand the balance of where potential kind of cash flow savings and generative free cash flow could go versus within the budget.

Yes. A great question, Paul. I mean, we look -- we feel like we've got the approval, the authority to -- if the opportunities exist in the basin to wisely invest $820 million. And today we're seeing all kinds of opportunities to invest that. And so, it's really a high-grading exercise that we do going inside of the organization. And we meet weekly on this to look at where are we deploying capital this week and how we improve our returns. And so a fun process to be going through. I mean what a great basin to be working in. And so, we are trying to generate the maximum amount of free cash flow we can from those invested dollars and we continue to have that healthy debate internal. And so, we'll continue that process. We'll be very active on our investment. And I would be willing to be nimble and change direction as we see real opportunities out there. And so, hopefully, that answers your question. That's kind of the way we look at it internally.

Yes. Just maybe just one real quick follow-on there. You mentioned kind of meeting weekly on there. Has that process changed over the last two quarters of non-operating a little bit? How does -- not just non-op but maybe op and overall managing the capital program is becoming more active. And certainly, has there been any internal changes in that direction?

Yes, Paul. We've seen the big uptick. So if you looked at our non-op spending in the first three quarters of 2018 it was almost nonexistent. It really kicked off fourth quarter of 2018, which we talked about last quarter. And this quarter, we've almost spent half of our projected allotted budget for the entire year in the first quarter. Those were great things to invest in and we'll continue to manage that inside of our program. But, yes, it's caused us to meet a lot more and really look at the results of the offset operators. We've got a non-op team that's really gotten proactive. They're doing a lot of great work understanding the other operators and what they think -- we think they can deliver and how their wells are looking. And so, we're spending a lot more time with a non-op focus when it could be 40-plus-million-dollars of our $820 million.

And I'd like to jump in just so -- permit on that Paul. It's Eric Hagen. Just to -- Jason Finch, our new VP of Planning, they do meet weekly on this. I sit in most of those meetings. And this quarter is a good example. Our CapEx came in where we expected it around $220 million. The infrastructure and capitalized workovers and land, which is somewhat discretionary, are -- all came in light. Non-op came in a little bit heavier. But the balance of it is we think we made good investments and we came in on our target. And that's really the objective and what we're committed to doing throughout the year. So --

No. Thanks. That's the color I was looking for, just trying to understand how the organization has changed over the last 18 months or so, in terms of addressing that, especially, over the last couple of quarters, as Brad mentioned there. So appreciate all the color. It's great. Thanks.

Thanks, Paul.

Our next question comes from Marshall Carver of Heikkinen. Please go ahead.

Yes. Good morning. You talked about seeing some growth in the second quarter and a stronger growth in the second half of the year. Was that for the whole company or just the Williston? And when you factor in Redtail, could you talk about the quarterly growth trajectory?

Yes, Marshall. Thanks for the question. Absolutely, I mean, we see double-digit growth in the overall volumes in the Williston. As we pointed out, we had a 10% year-over-year growth quarter -- this quarter and a 2% quarter-over-quarter. And so we continue to see the Williston Basin volumes increase. As Redtail moves down it's declined, it becomes less and less of the total volumes. And so, Redtail has less and less of an impact on that negative decline. It was fairly steep as you saw in the first quarter. But at the volumes that it currently performs at, that becomes less and less of a drag. And so the overall company volume increase, you should see that accelerate as we move into the second half one, because we have a lot more POPs coming on; and two, just frankly, because the Williston becomes more and more of our total.

So you would expect quarterly growth for the whole company each quarter this year?

Yes. That's what our budget shows.

Okay. Thank you.

Our next question comes from Biju Perincheril of Susquehanna. Please go ahead.

Hi. Thanks. Good morning. So this -- the uplift that you're seeing from the parent wells that you showed here it’s quite impressive. So I was just wondering is there a way to quantify that inventory of understimulated parents -- parent wells probably looking at vintage of the wells or proppant loading or fluid loading of any of those variables?

Yes. Biju, thanks for the question. That's a great question. We -- it's caused us to go back and look at our entire 1,500 existing wells and look at the timing of the original completions. And so if we are offsetting a Gen 1, Gen 2 completion that was 7 years to 10 years ago. We think we have a great chance of possibly stimulating that. We've actually done some more recent completions where we've done it against wells that are not as old so maybe wells that are three to four years old. We haven't seen as much as an uplift but we've still seen some uplift which is what you would expect. And so there's going to be an economic dynamic there. And I think some of our other operators in the Bakken have tried stuff like refracs. I think refracs and these offset stimulations are both telling you that there's more economic oil in place than there is to get after in the basin. So I think we'll continue to figure out what the economic alternatives are and how to -- what's the superior way to get at these reserves. But we continue -- as I said in my opening comments this is not something we expected and we're really pleasantly surprised to see how large the increases are and how long they're lasting. I think slide 20 that we highlighted before those wells are also flowing. And so this is not the new wells and the parent well frankly. So this is not ESP-assisted. This is the natural flow from the reservoir in all those cases.

I would also say some of those wells they're Gen 5s so they're cheaper. So we're seeing capital efficiency see more production and cheaper wells.

Got it. So then I would imagine that inventory is quite substantial. Is there a way to direct your near-term drilling plans to go after some of those parent wells and I guess boost your overall capital efficiency that way, just getting the benefit of the parent well uplift as well?

I like how you're thinking. I think we're wrestling with all that internally and how -- one of our real keys that drive efficiency into our program is a pretty stable program and steady program. And so we started moving that program around a lot. We caused a lot of unnecessary capital CapEx in the program. And so really having a long-dated view of this being an operator that plans to be in the basin for the next decade and how we optimally recover the reserves under our acreage these are all things that we're talking about. So it is causing us to think about in greater detail where the parents are where the offset wells are and how to take maximum advantage. I mean we are all -- it's all about economics for us. We're running economic models. And to the point that the parent well gives us a 10% increase in free cash flow 10% to 20% uplift in IRR then we're certainly trying to factor that in our economic equation.

Great. Thank you.

This concludes our question-and-answer session. I will now turn the conference over to Eric Hagen for any closing remarks.

Okay. Thanks, Andrea. Whiting will be participating in the Tudor Pickering, Hotter 'N Hell Conference on May 14 and the DUG Rockies Conference on May 15. And now I'll turn the call over to Brad Holly for closing remarks.

Well, thank you, Eric. I want again to thank my fellow Whiting employees, the Whiting Board and our shareholders. We are beginning to see the fruits of our strong corporate culture, which is at the core of everything we do. More effective communication, a focus on business results from the wellhead to the corporate office and industry-leading innovation are driving strong results. We are poised to gain even more momentum in the second half of the year and we remain committed to repeating our 2018 achievement of delivering peer-leading free cash flow. We are pleased with our progress, building on our success and taking the right steps to drive free cash flow growth and shareholder value creation. Thank you for your interest in Whiting and we look forward to updating you again soon on our continued progress.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.