Thank you, Rocco. Good morning and welcome to Whiting Petroleum Corporation's third quarter 2019 earnings conference call.

On the call with me today are Brad Holly, Chairman, President and CEO; Correne Loeffler, CFO; Chip Rimer, COO; Tim Sulser, CSO; and Kevin Kelly, our Vice President of Marketing and Midstream. During this call, we'll review our results for the third quarter 2019.

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 two of our corporate presentation and in our earnings release.

With that, I'll turn the call over to our Chairman, President and CEO, Brad Holly.

Thank you, Eric. I am pleased to report that our production came in above the midpoint of old guidance and capital expenditures were below the low end of the guidance range.

In the face of the challenging operating environment in the Williston Basin, our team delivered solid results. We are beginning to see the positive effects of our recently implemented strategic reorganization.

This was demonstrated by the coordination and positive results produced by our team in the field. While we have a lot of work to do, the Whiting team is energized in its commitment to becoming a leading value-based E&P that can maximize cash flow.

During the quarter, we faced weather challenges including significant rain and flooding. As a result of our efforts to develop a more streamlined organization, our field employees were able to keep operations moving and hit our production goal.

This illustrated what is occurring all across our organization, a simpler, flatter corporate structure is driving better communication and teamwork. New planning processes backstopped by a better use of technology have also enhanced our capabilities.

Our employees in the field and at headquarters have better access to real-time data through new performance dashboards. These automated reporting tools allow for enhanced surveillance and management of high value wells.

This gives us the ability to prioritize our time and energy to enhance profitability. It also gives us greater flexibility to course correct in the face of external challenges.

We have also gained greater insight into our cost structure through the expansion of real-time data reporting, allowing us to advance our goal of driving down lease operating expenses by 10% to 15% in 2020. The company has a number of initiatives underway to achieve these savings.

The most impactful of these include optimization of chemical and fresh water programs, renegotiation of saltwater disposal contracts, more efficient distribution of produced water, improved focus on run-time and effective utilization of rental equipment. Our north polar area provides a good example of how our cost savings initiatives in the field are bearing fruit.

We institute a rigorous review of our software disposal program in the area, we examine everything from our contracts to how we hold that water by rationalizing our vendors and optimizing our logistics we are able to eliminate approximately $2.5 million of cost annually. This equates to a 40% drop in cost to transport and dispose per barrel.

We have also gained greater insight into our capital program through our performance dashboards. We can track spending on projects in greater detail, which allows us to optimize the development plan from the initial drilling of the well through our facility build.

We are expanding this to a corporate level through a rigorous supply chain analysis that implements technology to better track and evaluate our vendors. We expect these initiatives to be important long-term value drivers as we regularly review our options to strengthen our cost structure.

Whiting's corporate optimization efforts are founded on creativity and innovation in the field. Our drilling department continues to lead the way in terms of drilling cycle times in the Williston Basin as depicted on Slide 10 in our third quarter slide deck.

Our drilling engineers also continue to be leaders in pioneering new technology. They successfully implemented a brine-based drilling fluid system in the Sanish area that resulted in a 25% reduction in rig hours for the vertical section of the curve.

The team has also designed and implemented new bit technology that is estimated to increase the rate of penetration by over 10%. On the completion side, our engineers are also delivering industry-leading results.

As depicted in our presentation on Slide 11, Whiting is a leader in the basin in stages completed per crew in 2019. This achievement was driven by increased surface efficiency, the detailed planning and reduced downtime during the completion process.

This allows Whiting to deliver wells to production faster and at a lower cost than our peers. I would now like to highlight two major areas where we have new results this quarter that set up years of profitable drilling for Whiting, Sanish and Foreman Butte.

These core properties continue to deliver positive incremental results setting the stage for expanded future drilling and maximizing cash flow. As depicted on Slide 6, we have completed four infill pilots that span our Sanish Field.

These were characterized by a significant uplift in child well performance and a positive interaction between the parent and the child wells. Our latest result was significant production history.

The Pod 9 project further built on our strong track record at Sanish. Our new wells there are beginning to outperform the parent wells, which are producing above their prior trend.

According to third-party analysis, we are a leading operator and generate the highest returns in the area because of experienced reservoir management. Sanish is an attractive area to operate.

In addition to the strong recent drilling results, we have better infrastructure availability here than in the center of the basin. When we sold our plant in the area we retained firm processing rights.

We have been strategically looping gathering lines to utilize this capacity and improve gas capture. On the other side of the basin, at Foreman Butte, we are also experiencing strong results.

To-date, we have drilled 17 wells that delineate the acreage. They have produced at 2.5 times greater than the initial wells drilled in the unit.

These wells are 82% oil. Our completion success stems from applying newer generation technology that incorporates higher profit loads, increased stages and additional perforation clusters.

Foreman Butte shows our ability to successfully execute on an attractive acquisition that we expect will provide multiple years of profitable drilling. This demonstrates our core competency infill development highlighting that our operations team is one of the best in unlocking value in mature plays.

Heading into 2020, we are shifting some activity to Sanish and Foreman Butte. This is to capitalize on the strong results we generate there and because we have higher confidence in infrastructure availability in both areas.

Again at Sanish, we spent money to maximize our access to firm capacity through line looping into the Robinson Lake plant. And at Foreman Butte, we are coordinating with third-party midstream providers to build-out infrastructure that sets us up for full scale development.

I'd like to end by highlighting our growing ESG program and discuss our thinking around 2020 plan. We published our 2018 Sustainability Report on our website this morning.

This is our second annual formal report and represents significant progress. We have systematically increased transparency, while indexing to the primary ESG frameworks.

Throughout 2019, we continue to improve in our reporting and selected four areas to focus on; supply chain, greenhouse gas emissions, health and safety, and diversity and inclusion. We are very proud of our progress in this area and remain committed to achieving peer-leading status on the [ES&G] front.

Regarding the 2020 outlook, we don't intend to provide detailed guidance until our fourth quarter call, but wanted to give you a little color. We remain focused on maximizing capital efficiency to enhance cash flow.

Production is an output of this equation. Consistent with other operators, at current commodity prices, we won't prioritize production growth.

Whiting shareholder value should be enhanced as we execute on our cost reduction initiatives, and continue to drive capital efficiency by reducing our drilling and completion cycle times. This should lead to expanded margins, lower CapEx trend and maximizing cash flow.

In addition, we have some cash flow tailwinds helping us. First, we have $50 million of cost savings from our reorganization that takes full effect in 2020.

Second, our Redtail oil deficiency roll-off in April, which translates into about $20 million of additional cash flow each quarter. Finally, as Correne will detail, we have established a goal to achieve $35 million to $50 million of additional LOE LOE savings in 2020.

I would now like to introduce you to our new CFO, Correne Loeffler, who joined the Whiting team in August. It has been a pleasure having her on our board.

She has a strong background in corporate finance and a keen understanding of the oil and gas industry that complements our management team very well. I look forward to continuing our work of driving financial and operational improvements.

With that said, Correne, will talk more about our quarterly results and provide an update on our initiatives to strengthen the balance sheet.

Thank you, Brad. Good morning, everyone.

It's my pleasure to be here speaking with you today. As Brad mentioned, our goal is to become a leading value based producer focused on maximizing cash flow.

To do this, we need a strong financial foundation. I'm going to start by reviewing the progress we have made to strengthen our balance sheet, provide some additional detail on the quarter and finish by providing further insight into the ongoing initiatives around optimizing Whiting's cost structure.

In August and September, we took the initial steps to address our near-term maturities. During that time, we have made progress in four areas.

First, in September, we secured an amendment to our credit facility, which allows us to use over $1.4 billion of the facility to repurchase Whiting senior notes. Second, we successfully tendered for $300 million of our 2020 convertible notes at a slight discount.

Third, we repurchased $100 million of our 2021 senior notes, again at a slight discount. Finally, we recently completed our fall borrowing base review where we reaffirmed our commitment at $1.75 billion and only slightly decreased our borrowing base to just over $2 billion.

With these steps we are positioning ourselves for a successful refinancing. We are diligently evaluating multiple financing alternatives.

Despite the challenging backdrop of the capital markets, we are confident in our ability to manage our near-term maturities. On the production front, we are maintaining our full year forecasts.

I want to add my appreciation to the team in the field for their hard work and determination that kept the production flowing despite challenging conditions within the basin. That really speaks to how the team has come together and is focused on executing the program we promised.

Heading into the fourth quarter, we expect production to remain relatively flat, despite a seasonal drop in activity. We are also tightening our full year guidance range for CapEx.

The range implies we will spend approximately $134 million to $154 million in the fourth quarter. Given the team’s ability to track and monitor well costs in greater detail, the team is comfortable narrowing our CapEx range.

Going into the fourth quarter, we are running four rigs but have dropped down to one frac crew. One crew is typical for this time of year as we reduce activity going into the winter.

During the quarter, we plan to put on production at backlog of wells that were completed and largely accrued for in the third quarter, which leaves us with roughly 50 DUCs as we exit the year. Moving to our cost structure.

LOE was slightly elevated due to several one-time expenses that added approximately $0.30 per BOE to LOE for the quarter. We expect these costs to normalize in the fourth quarter, as our cost savings begin to take hold.

Now turning to G&A. For the quarter, our G&A included $8 million of one-time charges related to the reorganization.

We expect G&A related expenses to decrease to $1.95 per BOE, which is the midpoint of our range in the fourth quarter as the savings from the reorganization take effect. Looking at differentials, our oil differentials were higher than expected.

This is because of the narrowing Brent to WTI spread, it reduced the value of the barrels on the rail. Additionally, the delay of the Enbridge Line three pipeline is expected to weaken differentials into the fourth quarter.

The latter increased the number of Canadian barrels flowing south that competed with our Williston Basin barrels. These factors are amplified by normal seasonal decline in demand, which is largely due to refining turnaround.

Therefore, we are moving up our oil differentials guidance for the remainder of the year. Moving on to natural gas and NGL pricing.

At the macro level, gas and NGL system is congested on both the processing side and pipeline capacity out of the basin. This is leading to lower realized pricing.

The expansion of select gathering system, several new gas processing plants and the addition of the Elk Creek NGL pipeline should provide flow assurance and improve our pricing. I'd like to finish by elaborating on our cost structure initiatives.

We are focused on improving our cash margins, which were significantly enhanced by streamlining our organization. This led to the estimated $50 million of annual cost savings, most of which will be realized in G&A expense.

During the third quarter, we have focused on implementing a number of rigorous programs to further optimize our cost structure across the board. As Brad mentioned earlier, the team is targeting a goal of reducing our absolute LOE by 10% to 15% in 2020 when compared to 2019 levels.

This translates into approximately $35 million to $50 million of annual cost savings. Further, we believe there is more work to be done on the non-payroll G&A front.

Some of the larger G&A initiatives include optimizing the size of our fleet program and maximizing the value of the dollars we spend on our IT, software and subscription. We expect these initiatives will begin to materialize in the fourth quarter, but we expect to see an even greater impact in 2020.

However, this is only the start. We are going to continue driving these types of initiatives as we move forward on our plan of becoming a leading value based E&P producer.

Operator, with that, we'd like to open up the call for Q&A.

Brad, could you or one of the folks there, I'm looking particularly at Slide 9, just talking maybe a little bit more on the infrastructure constraints. Could you maybe expand just, I guess, two fronts there, one, it does look like you're shifting to what I would call just as it says on that slide, higher confidence areas, maybe talk around that.

Secondly, just your confidence, I know there has been obviously a couple of quarters with some constraints here, just your confidence of between now and year-end and as we get into 2020, just the confidence of things coming online that will alleviate this.

Sure, Neal. I'll take the first part of that question and I'll turn it over to Kevin Kelly to give you a little more detail.

We do see infrastructure coming on, it appears to be largely on time. And so, we're watching the start up of those systems what's that's led us to do, though, in 2020 is in the first part of the year really move our activity to Sanish and Foreman Butte as we talked about, because we have real confidence in flow assurance there as the systems become operational and get the bugs worked out in 2020.

I will have some development back into the center of the center of our acreage position here.

Sure, Neal. I'll take the first part of that question and I'll turn it over to Kevin Kelly to give you a little more detail.

We do see infrastructure coming on, it appears to be largely on time. And so, we're watching the start up of those systems what's that's led us to do, though, in 2020 is in the first part of the year really move our activity to Sanish and Foreman Butte as we talked about, because we have real confidence in flow assurance there as the systems become operational and get the bugs worked out in 2020.

I will have some development back into the center of the center of our acreage position here.

And then just then just one follow-up, just Brad your confidence just on, as you look at the inventory going into 2020, you're obviously like what is it, your slide eight shows, moving to the full-field development in Foreman Butte. So I’m just wondering could you just talk about the confidence in core inventory overall, I know that seem to be an issue not for just you all, but for a lot of the companies out there.

I just wonder if you could talk around the confidence around that.

We talk about ours a lot. We probably refer you to multiple sell side and vendor reports that show kind of 7 years to 10 years of inventory on our acreage.

I'll tell you we kind of targeted 30% IRR on our projects and that's consistent with our current program. Currently, we have about 250 locations to drill in Sanish, 75 of which of those are Bakken wells and we continue with the cost structure that we've talked about by taking significant dollars out of our cost structure and our excellent performance from our capex teams on drilling and completions.

We're working on moving stuff that might be mid-20s or teens up into what we would call that 30% IRR kind of project. So, if you notice the curve on Foreman Butte the separation between the parent wells and the child wells is continuing to increase, we're at about 70 days now, 2.5 times better.

But we're watching that closely and every day that those wells perform we get more and more confident in the economics around Foreman Butte.

So North Dakota has indicated gas recovery recapture rate in July and August were 81% below the 88% threshold. I know, Whiting has made a point of being above that threshold.

And just curious how much that was weighed on your price realizations this quarter? And then given increasing GORs overtime and continued basin production growth, curious, if you believe the gas processing capacity additions are sufficient to meet the November 2020 deadline, you increased the state threshold of 91%.

We had a slide in our deck recently that we presented at Barclays that really showed, since 2015 Whiting has been totally committed to meeting the gas capture requirements in the state. We think that’s what a prudent operator does and we think it’s very important to meet those standards.

So, you’re correct, we spent millions of dollars in processing capacity and committing our volumes to make sure that we can meet those standards. So, we are working toward the November 2020 increase in requirements and I feel confident that Whiting will be able to deliver and achieve on that.

And as Kevin mentioned earlier, I think there is significant gas processing come into the basin. And by our slide on page nine, we’re showing that we do think there will be ample capacity in the short short-term, you bring up a great point though we have seen better well results in the Bakken.

We’ve seen more gas, especially in the center of the basin and we’ll continue to try to make better and better wells and make more gas. But right now we feel confident about the infrastructure that’s coming into place to handle that.

And then it sounds like to 10% to 15% reduction on LOE is on an absolute dollar value irrespective of sort of production volumes. Where are you in terms of optimizing those costs and renegotiating some of those contracts?

Chip Rimer in our operations team has just done a phenomenal job. It wasn’t a new thing that we woke up and started in the third quarter, they actually started in the first quarter.

And as you can appreciate it, probably, it takes a lot of momentum, because it has a lot of moving parts. The current team has over 75 individual initiatives that they are working on to drive those costs out of the system and we meet weekly to discuss those.

And so every week we hear of small wins, some weeks bigger than others, but they are literally going through absolutely every dollar that we spend on the LOE front and how we can do that better. And so, we've got some momentum internally, it's exciting to watch week over week what they're doing.

And so it's in process, but as Corrine mentioned, we'll plan to see part of it. Here in the fourth quarter, you'll start to see it, and then we expect that to roll through 2020.

Your slides 10 and 11 show some significant gains in capital efficiency. Just wondering if you have some well costs that you can share that go along with those anything in terms of year-over-year type per foot savings you're seeing.

I know it varies by area, I think that gives us a sense of what kind of well costs you have now and where you see those trending?

these slides are very, very hard to actually achieve. And it comes from real dedication inside the teams to work proactively with our partners, and we actually listed our partners on Slide 10 there.

That is year-over-year-over-year relationships with those drilling contractors. As you can see there's three drilling contractors producing those results.

So it's not just one particular fleet, it is really listening to our partners trying new things. We have a culture where we want them to try new things.

That's the only way we're going to make significant innovation and process improvement. And so, they are not developing our wells from a defensive position where we're scared to overspend, they are trying to implement new technology every day, and you're seeing big wins in that.

And that's the only way you get a 20% reduction from 2018, which was very good at 10 wells per day. And so we're right in the middle of RFQs on all of our CapEx for next year.

So we are talking to absolutely all of our vendors from tight to completion to the rigs right now and working on what we think the cost will come out in 2020. So, we're seeing good progress on that.

We're seeing the market soften. And there's going to be two components to the 2020 CapEx program, it's going to be the innovative work of our team to drive those costs down as well as we think a softer market that will help that as well.

And so, right in the middle that might give us a little bit more time to lock that in and we'll be out with those costs.

And I imagine you're bit reluctant to talk on 2020 that given you haven't put the formal plan together yet, but just trying to get a sense of you're down to one completion crew now and I realize you'd like to go slower during the winter months. But given some of these constraints on processing and NGL takeaway are coming off, how do you see, say, even like the first quarter of 2020 would you think most likely stay at that one crew or would you take advantage of the constraints coming off and start to ramp back up?

Great question, and exactly what we are debating internally. I mean, costs are higher in the winter, which impacts our capital efficiency.

And so going to one completion crew is not abnormal. We think it's the best use of really the capital efficiency metric right now.

We do not plan to stay at one crew long term. We'll be ramping those back up and based on the factors that you said the winter conditions, the capacity that's available, the DUC inventory that our drilling organization builds for us, we’ll get back out those completions as early in the New Year is practical.

And so I think what you’ve seen from us, Mike, as you haven’t seen us deviate a lot on activity, we truly believe to be our core competency to be a great developer of assets. We’ve got to have a fairly stable program to be able to drive these efficiencies into the program.

So when oil ran up in 2018, you didn’t see us run out and that will add a lot of rigs, in fact, we had zero. And so in the last two years, we’ve been really stable kind of on our drilling and completion front.

And I would expect to see some very similar from us in the future.

Just wanted to get a sense of whether or not you guys were still seeing significant loss volumes or shut-ins due to lack of processing capacity in the basin here in 3Q and and do you see that persisting into 4Q. And do you think that that just improves dramatically as we get into 1Q, just trying to get a bit more of quantification around the midstream benefits you guys might see.

And we don’t see a lot of production shut in. I think, on the second quarter, we slowed completion activity and we changed our guidance to try to account for what we saw going forward.

So, I would say that our activity and our availability out of the basin was largely in line with how we saw a quarter ago and we continue to work to build to fill that in the most cost-effective way. I would say that what was really amazing in the, in September, we had over eight inches of rain in the Williston area and the county roads in that area were shut for a third of the month and yet when the county roads are shut, you can’t run any oil or water trucks, any hauling and our team did an amazing job out in the field as you could see in the slide deck to have a very short downtime and to get us ramped right back up on rate and tremendous amount of work and effort that went into that.

But we were able to deliver and we anticipate full anticipation that will continue to be able to deliver going forward.

And I guess, I certainly appreciate the fact you guys don’t have 2020 guidance out yet, but just to follow up on a comment that you made. You talked about how production growth would be an output next year.

So, just wanted to philosophically kind of get an understanding of what you are trying to prioritize and maximize here. I really just trying to maximize free cash flow yield in 2020, is that sort of the overarching theme or how would you sort of characterize the priorities?

I think, we are, we’ve got a real high priority on paying down debt and remaining capital discipline and that’s how we’re looking at it. And so we really believe that through innovation and technology, we can drive better margins.

And so we are looking at internal rates of return that we can generate from our drilling program and really looking at driving cash margin into our business. And so that is what we're focused on in driving and trying to maximize.

And I guess, obviously on oil differentials, certainly, bit disappointing to see those kind of widen out here. Do you have any kind of foresight as to when those might improve?

Do you think those can kind of get a lot better early next year, or what are your thoughts on Bakken there?

Let me turn that over to Kevin Kelly.

So yes, on the oil guidance, the widening out that we saw was a combination of couple of things we touched on in the prepared remarks, one the TI to Brent spread. And then as well as reliance more on and that influence the rail, and then as well as the Line 3 delay.

We do expect to continue to rely on rail into 2020. We don't expect to see new pipeline capacity additions until late in 2020 or the beginning of 2021, at that point, we start to see some relief.

Obviously, your view of what plays into the production profile of the basin can influence it. But those are the drivers that we're seeing going into the widening into the fourth quarter and expect that to somewhat play out into the early parts of 2020.

So building on an earlier question surrounding well costs, I was wondering if you could just give us a sense of where operated CapEx per rig what that looks like, just on your leading edge cost structure.

Well, just looking at CapEx, in general, we do expect CapEx to be coming down from the current level just given infrastructure spending, the one-time infrastructure spending that we are needing within 2019. And then we're also being able to see some of the efficiencies that we've talked about that will overall, whether it's the efficiencies on the completion side, drilling side or just overall costs that we are seeing.

So, I think, going into next year you're going to see just the lower level of CapEx, just with those in mind.

And then you made a comment there that was a good segue into my next one. Earlier, I think, Brad was talking about some infrastructure spend in the Foreman Butte area entering 2020.

Should we be thinking about that as similar to the Ray gas plant, should we be thinking about the amount of spend is similar to the Ray gas plant spend or is it less? Just trying to understand the evolution of infrastructure spend between 2019 and 2020.

Yes, the infrastructure spend that we're currently looking like is very minimal amount in 2020, we expect to be down from less than kind of the infrastructure spend with the Ray gas plant in 2019.

And then just one final one from me, I think, there were some discussion last quarter on potentially monetizing non-op to further reduce leverage. Can you just give us an update on just where you are today and what the path for the non-op monetization's look like?

We are always active in the divestiture market. We believe that price prudent not to provide specific details, but I'll tell you we're active in that, but I guess our commitment that we will not divest assets that are credit dilutive.

And right now we haven't executed on any of those, but our non-core, non-op stuff, is certainly something we continue to look at and are willing to divest of those if we get acceptable bids on us.

Hi, good morning folks. I'm trying to understand the interest expense impact of moving the convert on to your revolver given it has a low coupon right now.

Can you quantify what the interest expense would be if that full $562 million is on the revolver next spring, just trying to understand the delta between 1.25%?

Yeah, I don't have the exact numbers in front of me, but you're absolutely right. The 2020 converts at 1.25%, our credit facility has a LIBOR pricing grid based on it.

So, call it somewhere around kind of 4.5%. So, it is a slight uptick to overall interest expense.

We were comfortable going ahead and putting a We were comfortable going ahead and putting a portion of it underneath our credit facility because we’re really setting ourselves up for our refinancing in the future. We don’t need to put all of it on the facility at the time given the fact as you highlighted, it is a lower interest rate than our credit facility.

So, that’s more about just getting ourselves prepared for that successful refinancing in the coming months.

And then just a follow-up on that same theme, I appreciate the comments on the work that Chip Rimer and his team are doing in the field, but you’re talking to equity investors. The elephant in the room is that $1.3 billion of debt maturing by the spring of 2021 and I appreciate your confident comments currently on you think you’re positioned for a successful refinancing.

Can you give any more color or details to kind of give some comfort to the equity investors out there? Do you feel confident that a second, the secured debt deal can get done or what can you say out there to kind of maybe ease concern?

And I appreciate the question, and I understand the concern. I mean, as we have kind of shown within a short period of time we have taken several initial steps to position ourselves for this refinancing.

We’ve shown that our willingness to use a portion of our credit facility to repurchase the outstanding senior notes. In addition, as we kind of talked about we are continuing to evaluate several accretive non-core asset sales.

Therefore, the total amount we’re actually trying to refinance is much smaller. And then, for the refinancing, we’re continuing to evaluate a multiple alternatives that have a broad range of structures with them.

Ultimately, we can’t talk about specific deals, but we are focused on finding the best alternative to strengthen our balance sheet going forward in the coming months.

Just had a couple of questions, thinking about the Sanish area. Are there any other participants in the region that have also been looking to increase their capital investment there in the next year or so, or is it pretty much just you guys standing alone?

Noel, thanks for the question. I mean, there is, slide seven shows some peers that have been active in the area.

There is a small map on the left-hand side that it’s a little hard to read, but it gives us a lot of sticks on the map of well bores that have been operated in that direct immediate area in the recent past.

And I was just wondering as you do the shift in focus toward Foreman Butte and then back toward Sanish. Does that have any implications for sort of managing the overall portfolios base decline going forward.

I’m not sure if heading into this year you had a lot of visibility about how the capital spend might be changing from area to area.

Noel, we have a, as you know, we have a really large base out there of over 1,500 wells, which puts our base decline in really the upper 30s is the way we think about it. It can vary based on how big your wedge is from the previous year.

And now with that large of a base, I mean, we’re pretty locked in on base decline, it doesn’t change drastically moving forward. So, we do have initiatives internally to shallow that decline.

We have a multitude of production engineers that are in the field working hand-in-hand with our operators. And we constantly look at the base that's the cheapest barrel that we can go after.

And so a lot of internal focus on initiative on putting the right artificial lift in place, operating these well at their maximum efficiency and really work to get those barrels out of the ground and to a shallower decline. Through the dashboards that we described earlier today with predictive analytics, we've been able to decrease our wellbore failure rate by over 30% in the field.

And that has two big advantages one, the well doesn't go down and you're making zero production and have to spend money. And so they keep the wells on longer, which generates revenue and they run longer which is saving money on the workover expense side.

And so, we think about that base decline a lot at Whiting.

You all did a good job of kind of outlining all the various initiatives that you've got to try to drive LOE down. And I realize the complexities, I think, Brad, you mentioned there's like 75 different initiatives that are sort of being looked at.

But I thought Slide 12 sort of boil it down to kind of the six main areas that you're focused on to kind of drive those LOE reductions. And I'm wondering at just the high level, you can kind of say what has sort of already been achieved or will be achieved kind of by year-end versus some of the areas that will maybe take a little bit more effort or work or time to kind of achieve.

Yeah. Thanks for the question, John.

As you rightly outlined, it's an ongoing process and it's a continual process. And so, we've started to see some real wins like for instance and our fresh water and our produced water, water winds up being one of our largest expenses.

And what we found is that across Whiting's portfolio we were paying very different water rates in different places and so, bringing that together under a combined single head of water. We have a water resource and we have a water team and we're working with our supply chain groups to leverage Whiting size and scope in the basin to get a common water cost.

And what I could tell you is that cost has come down significantly and anywhere within Whiting's portfolio now there is a very minute difference in what we pay for water. And so we're seeing stuff like that.

Our teams have done a wonderful job especially in Redtail of reducing rental equipment. We have a lot of rental compressors and they've been able to creatively produce the wells better to save.

And so we continue to fill these costs back, but these are our larger categories. And we just had a very successful month of workovers.

And so we prioritize our workovers, instead of each office prioritizing workovers, we prioritize it over across the entire region and compete it for capital, stay to a budget and we did not see production decline from that program. But we saved significantly on our workovers.

So we're talking millions of dollars coming off here, John. So, each of these initiatives represents millions of dollars and we're working to have those come out of the system as quickly as possible.

And then my follow up with the Redtail deficiencies rolling off in April and then you mentioned just then that there has been some other progress on some cost efforts at Redtail, just curious if sort of the view on Redtail has changed at all sort of in a post-deficiency payment environment or is that an asset that we should maybe think of as potentially being marketed again without the burden of the deficiencies?

What we're committed to at Whiting is an active portfolio management. And so, if the CapEx -- if the wells compete for capital in our program they will get funded.

We have tons of confidence in our Redtail team, they’ve done a phenomenal job phenomenal job and we are totally convinced that they can develop economic wells out there and we have capacity takeaway. As you described, the deduct will go down significantly after April.

And we have some water contracts that we can use to our advantage out there. And so that's part of our 2020 plan.

We are looking at everything in our portfolio and the active portfolio management will allow the CapEx to rise to the very best stuff that we have internal to our inventory. So, I can tell you we’ve seen some positive results in our 2018 completions at Redtail.

We’ve also seen offset operators to the south of us drill on different spacing with a different wellbore trajectory and have produced some really nice results. And so, as we always do, we are studying Redtail intensely and it will be funded when it competes in our portfolio for capital.

Thank you, Rocco. Whiting will be presenting at the Bank of America Global Energy Conference on November 14 and participating in the Goldman Sachs Global Energy Conference on January 7th and 8th.

I will now turn the call over to Brad Holly for closing remarks.

Thank you, Eric, and thanks for your questions today. We remain dedicated to our strategy of focusing on margins, full cycle returns and generating free cash flow.

We remain focused on hitting our targets and strengthening our balance sheet. The new Whiting team is stronger than ever and committed to succeeding in this challenging environment.

Thank you. And we look forward to seeing you at the upcoming events.