Good day, ladies and gentlemen, and welcome to Laredo Petroleum, Inc.'s Fourth Quarter and Year-End 2018 Earnings Conference Call. My name is Mark, and I'll be your operator for today. [Operator Instructions]. As a reminder this conference is being recorded for replay purposes. It is now my pleasure to introduce Mr.

Ron Hagood, Vice President, Investor Relations. You may proceed, sir..

Thank you, and good morning.

Joining me today are Randy Foutch, Chairman and Chief Executive Officer; Rick Buterbaugh, Executive Vice President and Chief Financial Officer; Karen Chandler, Senior Vice President and Chief Operations Officer; and Jason Greenwald, Vice President, Reservoir Engineering; as well as additional members of our management team.

Before we begin this morning, let me remind you that during today's call, we'll be making forward-looking statements. These statements, including those describing our beliefs, goals, expectations, forecasts and assumptions, are intended to be covered by the safe harbor provisions of the Private Securities Litigation Reform Act of 1995.

The company's actual results may differ from these forward-looking statements for a variety of reasons, many of which are beyond our control. In addition, we'll be making reference to adjusted net income and adjusted EBITDA, which are non-GAAP financial measures.

Reconciliations of GAAP net income to these non-GAAP financial measures are included in yesterday's news release. Yesterday afternoon, the company issued a news release and presentation detailing its financial and operating results for fourth quarter and full year 2018. We will refer to the presentation by page during today's call.

If you do not have a copy of this news release or presentation, you may access it on the company's website at www.laredopetro.com. I will now turn the call over to Randy Foutch, Chairman and Chief Executive Officer..

Thanks, Ron. Good morning, and thank you for joining Laredo's Fourth Quarter and Full Year 2018 Earnings Conference Call. 2018 was a successful year for Laredo by many measures. We grew total production by 17%, increased the value of our proved reserves by 19% and maintained a strong balance sheet.

Our operational expertise continued to drive drilling and completion efficiencies, keeping well costs in check. And our previous investments in field infrastructure helped keep operational costs low as we delivered our 10th consecutive quarter of unit LOE below $4.

Moving forward, the company is well positioned for 2019, which will be a transitional year for Laredo.

As we talked about last quarter, we are executing a shift in our strategy, committing to align capital expenditures with operating cash flow by adjusting activity as needed and focusing our development plans on wider well spacing to drive improvements in returns and capital efficiency versus 2018 development, which was focused on inventory expansion and net asset value accretion.

As we execute this shift, we are significantly reducing our drilling and completion cadence, exhibiting capital discipline by cutting our expected spending by approximately 45% versus 2018. We are able to accomplish this as we have 88% of our acreage held by production and we've avoided long-term service contracts.

Slowing operations in 2019 is expected to produce both short- and long-term advantages for the company, namely, we anticipate that we will operate within cash flow for a full year 2019 at a WTI strip price deck of $54 per barrel and Henry Hub strip of $2.90 per million cubic feet of natural gas.

Additionally, we believe slowing development will begin to moderate both our whole and total production corporate decline rates, ultimately reducing our maintenance capital levels.

Once we have executed this plan in 2019, we anticipate being able to keep annual oil production flat in 2020 and 2021 from fourth quarter 2019 levels of approximately 23,000 barrels of oil per day, grow reserves and live within cash flow in a mid-50s environment, not including any additional savings.

As we have always done, we plan to adjust our workforce staffing levels and absolute G&A expense regularly as we adjust operational activities to operate within cash flow with these savings expected to be in the second half of 2019.

Upside to our cash flow assumptions can be realized through increase commodity prices, reduced service cost or better-than-anticipated well productivity versus our revised type curve, among other means. We feel that sustained oil prices in the mid-50s per barrel range could precipitate further service cost reductions.

Should additional cash flow be realized, we have the option of utilizing the excess cash flow for numerous purposes, including to pay down debt, repurchase stock or complete additional wells. To conclude, we have made an excellent start implementing this strategic shift we need to execute to drive shareholder value in a capital disciplined fashion.

We have shifted our development program to wider spacing to focus on increasing returns and capital efficiencies. We are exhibiting capital discipline with our 2019 budget that aligns capital expenditures and cash flow. And we expect further reductions in our controllable costs as we reduce G&A as our operational activity slows.

I will now turn the call over to Karen for an operations update..

Thank you, Randy. To start off, I'm going to walk through some of our reserves data, including PDP decline rates and our new type curve. Turning to Slide 5. You can see the updates to our reserves as of year-end 2018.

As part of our ongoing reserves estimation process, for our year-end 2018 reserves estimation, we incorporated additional production data to reflect the higher gas content and steeper oil declines on our historical wells and the negative effects on oil production from tighter spacing on our recent wells.

This additional production history has led to more particular forecast, including specific B-factors for both developed and undeveloped locations. The results of these changes were negative revisions to oil reserves and positive revisions to natural gas and NGL reserves with no meaningful change to overall EURs on a BOE basis.

In conjunction with this process, we also revised our type curve, which you can see on Slide 6. Here, we are showing a comparison over the first 5 years of the life of a well for the revised and historic type curves. A few points that are important to note.

First, while over the 50-year life of a well, there was an approximate 27% decrease in the oil EUR, there is only a 6% decrease in first-year oil production and only an approximate 15% decrease over the first 5 years of the well's life.

Second, in the revised type curve, the total recoveries increased 12% in the first year and 13% in the first 5 years. This dynamic drives very similar rates of return for the previews and revised type curves.

In addition to changes related to decline rates, the productivity assumptions of the revised type curve are based on assumptions for infill locations in some of our most highly developed areas and on productivity assumptions for areas and landing points that, in some cases, have limited data.

Slides 7 and 8 show Laredo's corporate decline rate for total production and oil, respectively. As it relates to oil decline rate, we expect this rate to moderate over the next few years as higher decline, tightly spaced wells drilled in 2017 and 2018 get older and as fewer new wells are brought on at a slower development pace.

Slide 9 demonstrates the oil decline projected for the tightly spaced wells that we drilled the past couple of years. Compared to both the previous and revised type curves, first year oil production is not significantly lower. However, it is in the subsequent years that the higher decline rates become more pronounced.

In total, for years 2 through 5, oil production for tightly spaced wells is expected to be approximately 30% lower than that for the revised type curve. There are a couple of important implications that result from this dynamic.

First, I mentioned previously that we expect our corporate oil decline rate to moderate as the tightly spaced wells get older. The negative impact of the reduced oil productivity will begin to lessen as we move through time. And I will note, this impact is already factored into the corporate oil decline rates we show on Slide 8.

The second important implication of this is the positive inflection point in oil productivity that should emerge as we finish completing tightly spaced wells and begin to complete widely spaced wells later in the second quarter of 2019.

The revised type curve expectations for oil production within the first five years are approximately 20% higher for widely spaced wells than the current expectations for the tightly spaced wells. Turning now to operations. As Randy explained earlier, we have shifted our strategy to operating within cash flow.

To accomplish this goal, with strip pricing of approximately $54 per barrel WTI, we will be adjusting our activity levels in 2019. At the beginning of the fourth quarter of 2018, we were operating four rigs and two completion crews. Turning to Slide 11.

We illustrate our planned progression of drilling and completion activity levels by quarter in 2019 for 3 different potential commodity prices, including strip pricing and both above and below strip pricing.

This optionality of drilling in completions cadence is achievable in large part due to Laredo's strategy of maintaining operational flexibility through high working interest and minimal drilling requirements. We have also traditionally signed service contracts of a year or less.

And as you can see on Slide 11, we will be moving to operating 1 rig by the second half of 2019. We were able to make this adjustment without paying any early termination penalties because of how we structured our rig contracts. We are currently operating 2 completion crews, and our completion activity in 2019 will be front loaded.

At the strip pricing scenario, we expect to complete 36 gross wells, 32 of which we expect to be completed in the first half of 2019. In the second half of 2019, we plan to adjust the number of completions to align with cash flow.

Should prices move down, we expect to complete a minimum of 28 gross wells and then we will have the flexibility to drop to 0 completion crews. Conversely, we can keep a completion crew longer and complete more wells should additional cash flow be generated.

Using current strip and service costs, we expect activity levels in subsequent years to approximate the 2-rig, 1-crew average for 2019. Like 2019, we would expect to front-load completions activity to work down DUCs built in the previous year.

On Slide 12, you can see the breakdown of our capital program at strip pricing, once again stressing the program will be adjusted based on cash flow generation. The company is focused on efficiencies and controllable costs can provide upside to our cash-generation capabilities.

On Slide 13, you can see one example of how much more efficient we had become year in, year out since 2014. Should we be able to continue to make gains beyond what are illustrated in this chart, we have the potential to continue to reduce our capital well costs.

We have factored into our 2019 budget actual completion cost savings we have negotiated at the beginning of the year, but we believe there are more opportunities for savings if oil prices remain at these levels. Slide 14 illustrates the continuous progress we have made on controllable cash costs.

LOE has been driven down, in large part, by the benefits of our prior investments in infrastructure. And as Randy mentioned, we expect to make further progress on G&A expense as we align our activity and staffing levels. I will now pass the call over to Rick for a financial update..

Thank you, Karen, and good morning. Fourth quarter and full year 2018 statement of operations and cash flows were included in our press release issued yesterday. We expect to file our annual report on Form 10-K later this afternoon.

Although fairly self-explanatory, there are a couple of items in the cost and price realization categories that fell outside of our previous fourth quarter guidance where some explanation may be helpful. Depletion, depreciation and amortization or DD&A in the fourth quarter of 2018 was $9.29 per barrel oil equivalent compared to our guidance of $9.

This metric is primarily driven by depletion, which typically represents slightly more than 90% of the company's total DD&A. As you know, depletion is derived from period production, total reserves and the undepleted base in our full cost pool.

For Laredo, that calculated rate is very representative of our depletion costs for proved developed reserves since we booked minimal PUDs and we do not carry a large unevaluated property balance, which is excluded from the depletion calculation.

Annual drilling activity during the year provides additional knowledge that assists in evaluating properties, resulting in the continuous movement of unevaluated property cost into our full cost pool.

Similar to prior years, in 2018, we transferred a net $45 million, equivalent to about 25% of our unevaluated property cost at year-end 2017 into our full cost pool. This results in only about 5% of our total assets being classified as unevaluated at year-end 2018.

Karen has discussed the changes in our reserves at year-end, but as a reminder, only about 9% of our proved reserves are undeveloped. And those undeveloped reserves represent about 6 months of development activities.

You will recall that beginning in 2015, we significantly reduced our booking of undeveloped locations to enable us the maximum flexibility to drill our most appropriate locations and at the proper cadence while staying true to the SEC guidelines.

The other outlier in our guidance was our natural gas price realizations, which were 17% of the Henry Hub benchmark, well below our initial expectation of 40% of Henry Hub. This is simply a function of the move into WAHA basis and how we derive the guidance amounts.

At the time, we provided guidance for fourth quarter 2018 natural gas realizations, we incorporated 1 month of actual WAHA basis and we used 2 months of strip prices. At that time, November and December 2018 WAHA basis were forecasted at a negative $1.47 and a negative $1.20, respectively.

Actual pricing for November and December of 2018 were a negative $1.74 and a negative $4.58, respectively. For all of our price realization guidance, this dynamic applies. We use any actuals to date and forecast based upon the appropriate product strip.

Looking to the future, our 2019 budget is based on the primary premise of balancing development activity expenditures with operating cash flow on an annual basis.

Using benchmark strip pricing of approximately $54 per barrel for oil and $2.90 per million cubic feet of natural gas, we believe that this translates into a capital program of approximately $365 million for the year, of which about 82% is for drilling and completion activities.

Unlike past years, this activity will create a limited inventory of uncompleted wells. This program, coupled with our high HBP percentage, a reduced PUD booking strategy and limited long-term contracts on rigs and crudes, provides added flexibility that enables us to make investment adjustments that balance operating activity with cash flow.

The substantial portion of our completions will occur in the first half of 2019. Consequently, we do expect to incur an outspend in the first quarter. We then anticipate to be approximately cash flow-neutral in the second quarter and then generate enough free cash flow in the second half of 2019 to balance spending and cash flow for the full year.

A key component of this budget flexibility is the structure of our hedging program. The structure of this program protects the company from a large downward move in the price of oil while we retain all of the upside if oil prices increase.

We have hedged approximately 90% of our anticipated oil production in 2019 and approximately 90% of those hedges are puts with an average strike price of $47.45, not including premiums paid or deferred.

In summary, we're committed to targeting cash flow neutrality for full year 2019 and we believe we have the operational and financial flexibility to achieve that as we continue to focus on controllable cash costs.

We have a solid financial structure with significant liquidity to capitalize on appropriate opportunities, we have a consistent hedging program to protect our anticipated cash flows and we have no debt due for three years, all of which provides a strong foundation for the company.

Operator, at this time, would you please open the lines for any questions..

[Operator Instructions]. Our first question comes from the line of Brian Singer of Goldman Sachs..

Two questions with regards to the new type curve and the timing of the more widely spaced wells.

As you slow activity and CapEx in the second half, can you just give us or remind us what your expectations are for how many widely spaced wells would come online by quarter over the course of the year? It seems like that's disproportionally 3Q and 4Q or maybe 2Q, 3Q, 4Q?.

I think I'll let Karen give you -- Karen or Dan, but it's -- we came in through the end of '18 with the number of wells in process and so we'll work off that inventory and then start the wider spacing..

So the well count numbers as we're coming in through the first quarter 2019, that's kind of the transition time. We've got 15 wells that will be finishing up completion-wise in this quarter.

And then as we role into second quarter, then we move towards the wider spaced wells as we kind of finish up, at least in the current plan, those completion activities. So that would be the remainder of the wells after the 15 that we'll be completing internally..

Got it. Okay.

And then my follow-up is do you have -- what's the longest history, if at all, that you have wider spaced walls online? Or will these be the first ones you're testing? And I kind of asked to see if what you're saying on Slide 9 is it's really the second year where you'll see the differentiation in terms of a lower decline rate relative to the tightly spaced wells, when we would start to see that evidence? Is that more of a late 2020-type event? Or will you be seeing results from any wells that you may have in the hocker that you already have online?.

Yes, we've said for -- Brian, we've said for a long time that production history matters and we never liked, as you know, claiming lots of early on information as being relevant. We've had some different landing points and so on and so forth.

But Jason, do you want to address specifically?.

Yes, sure. This is Jason. In terms of how much production history we've got on wider spaced wells, the answer is several years. So going back into 2016, in particular, those were significantly consistent with what we're planning to do on a going-forward basis. So that's the production history that we've got, going at least back to 2016..

And our next question comes from Derrick Whitfield with Stifel..

And I'll pick up on Brian's question and perhaps ask this for either Randy or Karen.

But based on Karen's earlier comments, is it possible that your revised type curve is overly punitive in light of your broad D&C optimization efforts since 2016?.

We've tried to play middle-of-the-road and not be -- and not push the data one way or another. I think we've tried to be completely straightforward and get the conclusions the conclusions that the data gives us at the time. Obviously, when you look at the curves, some of these data took 2 to 3 years to materialize.

That doesn't mean there's not, perhaps, upside. But where we are today, this is how we see it..

Understood. And then if I think about the PowerPoint and discussion, most of it has been focused on the productivity of your new type curve.

Could you speak to the current expected costs of these wells? And what tweaks you plan to test in low density development that could improve the cost side of the equation?.

Yes. I'll let Karen give that numbers, but we kind of took the same approach on costs. We're using, as we've always done. We did see some perhaps some softening in service costs that we know is there that came about in the last couple of months. We used that because that was factual. We have not projected additional service costs in any of our numbers.

But Karen, do you want to....

Yes, so we've continued through the last quarter -- a couple of quarters to see some improvement, again, continuation of drilling completions efficiencies, and then also some service cost reduction, working hard with our service providers to look at the overall cost structure.

We've seen savings, a couple hundred thousand trimmed off in the last quarter, so continuing to make good progress there on well costs. As we continue to kind of look at the broader spacing, we'll continue to look at completions optimization around sand volumes, water volumes optimization and others.

So there's certainly still potential to keep working on the well costs and make good progress and we expect that to continue. There may be more service costs depending on commodity prices and we'll continue to work that..

And our next question comes from Joe Allman of Baird..

My first question is could you respond to the 13 data SailingStone filed this morning? And the way I see it, SailingStone is suggesting 4 things. So first thing would be lower G&A to the tune of like 50% lower. Second would be return -- focus on return on capital while prioritizing free cash flow and return of capital.

Third thing is a reasonable business plan with management compensation aligned with that plan. And the fourth thing would be pursuing strategic alternatives..

Joe, SailingStone Capital has been a long-time shareholder. They did file a 13D this morning. And we engage in lots of communication with our shareholders and we value their input. And I think I'll just stop there..

Got you. Okay, my final question is, in terms of the spacing plan, where ultimately do you expect to go to? I know on one of your slides you're showing kind of the NAV optimization and then the rate of return optimization.

Are you moving towards the rate of return optimization? Or are you moving towards the NAV optimization?.

We announced, Joe, in the third quarter call that while we were -- had spent a fair amount of time -- effort trying to really maximize NAV over the inventory that we had. We felt like that has added substantial inventory. We recognized and then talked about it for a while that there were some degradation in reserves and productivity.

But we announced in the third quarter that we were not going to continue focusing on NAV, that we were going to go for broader spacing and drill just better rate-of-return wells. And that's what this strategy shift for us is all about..

Got you. And just to clarify that one. So I know, originally, Randy, I think the NAV approach would have had potentially like 32 wells per section or 24 wells per section. And right now you're our ROR optimization is looking at 4 to 8 wells.

So are you actually moving to 4 to 8 wells per section overall?.

Yes, I think that's directionally where we're going. There are some zones that probably lend themselves to 8. But I think directionally, that's what you should think about..

And our next question comes from Richard Tullis of Capital One..

Randy, looking out to 2020, 2021, I know you mentioned you would likely be able to keep oil flat with the 2019 exit rate.

What specific D&C CapEx would be associated with that? And what sort of oil price would you be thinking about for those two years for the associated budget?.

We used -- I think we said that we just kind of used strip pricing going out in those years and that's -- that basically makes D&C costs relatively flat the next couple of years.

I think there's some -- again, I referenced the fact that there are some things that could be enhancements of that, including pricing, including production and service costs, including better performance on the type curves, but we're basically using strip prices.

I think the message is that the 2020 program, the way we modeled it is about the same as the 2019 program..

Okay, that's helpful.

And then, secondly, what's the rough split between zones for the 2019 drilling program?.

The 2019 drilling program, 2020 is going to be about flat. We're focusing pretty much on the upper and middle. As we've said a lot, we have a lot of client inventory, we have a lot of inventory. I think 2020 is probably a little more weighted towards the Middle Wolfcamp, but it's going to be Upper and Middle..

Our next question comes from the line of Kashy Harrison of Simmons Energy..

So in the prepared remarks and the press release last night, you highlighted anticipated corporate cost reductions in the second half of '19.

So either for Randy or Rick, I was just wondering if you could give us a sense of what you're planning in terms of G&A reductions on a dollar basis?.

Yes, Kashy, this is Rick. Similar to what you saw in 2015 when we saw a significant drop in commodity price, at the end of '14 we modified our operating programs, significantly dropped the amount of activity. The cuts that you would be seeing in 2019 I think are going to be appropriate relative to the rig activity that we do.

We're going to balance that with the timing of when that activity takes place. If we see, as Randy talked about, changes in commodity prices or service costs that changes our cash flow, we may modify the rig activity and completions along with that, which drives a lot of the G&A costs associated with that..

Got you.

And then, I guess, maybe my follow-up -- my second question, and this one might be for Karen or for Jason, but just -- I was wondering if you could just walk us through the ultimate gap in understanding between the actual results and the expected results on the historical wells, which employed the appropriate spacing? So why do we employ a higher B-factor initially? And what was missed in the initial analysis that ultimately resulted in a lower B-factor?.

I'll take first crack at that. As we try to show in the deck is that where we saw definitive production history was in a couple of out-years. They tracked pretty close initially, and I think that was really the eye-opener.

And then the '18 drilling where we drilled pretty tight spacing, thinking that was the NAV inventory approach, we saw those results much quicker. Jason do you want to....

Yes, I guess, the thing I would emphasize is the additional production data that we've been talking about for quite some time.

And to pick up on what Randy is talking about, with the denser spacing in the more recent drilling, that was having us take just a little bit harder look more broadly at all of the production data that we had to come up with our current interpretation..

I guess what I was trying to understand more so was on the -- I guess, we have a higher -- we had a higher B-factor because we thought we were going to get a higher terminal oil production curve. And even on these new wells, these new wells should be in theory be comparable to the wider spaced wells in the past.

So really what I'm trying to get at is, is our understanding of longer-term production in shale evolving just -- I mean, that's really where I'm -- more so I'm going with this.

Are we just overestimating the recoveries in the Midland Basin right now?.

I don't want to -- yes, I think I can speak a lot about our properties. And on Page 6, I think that's -- that is our forward-looking curve, that's our understanding.

And we've said -- this is interesting, I think, to us, is that we've said for years that as this production ages, it would get gassier, and in fact, we showed slides in which we had our GOR increasing out over 5 years. Now what we've done is we've taken a forward-looking curve and pushed that out and that's on, I think, Page 6.

It kind of gives you where we think we are today..

And our next question comes from Sameer Panjwani of Tudor, Pickering, Holt..

So I think it's been a while since we've gotten an inventory update.

So could you share some thoughts regarding remaining locations between the upper and Middle Wolfcamp, assuming the new 48-wells-per section spacing design? Maybe a low end and high end to correlate the difference in potential spacing?.

Yes. And that's a good question, appreciate that. So this is Jason. On the total inventory figures, the figures that we have talked about in the recent past are 1,600 total locations. And those figures, in total, that hasn't -- our current spacing and development approach hasn't changed those figures..

Okay.

And to clarify that, that's just between the Upper and Middle Wolfcamp?.

No, that's all zones. And so that's -- and the 1,600, just to make sure that, that's clear, that's 8 locations per section so that's 1,320 co-development..

Okay, okay. Great. And then circling back to the type curve conversation. Just trying to reconcile the difference between the oil cut in your type curve, up 31%, and in your reserves, up 26%. The reason I asked this is I think this is the second time in recent memory that oil cut has been adjusted.

So I'm just trying to get a sense of your comfort level with the go-forward curve relative to kind of what the reserves are saying?.

Rick, you want to....

Yes. Keep in mind that the reserves are the remaining in reserves that does not include the production at the early life of those wells and we've got wells included there that were drilled back in 2008 and '09.

So what you're seeing in the type curve is from day 1 of a new well, which is going to be higher, and as you saw on Page 6, that oil tends to be more front end-loaded and so you produced off some of the oil that's in the reserves.

Since we do not book a large amount and really just a minimal amount of PUDs, you don't receive the benefit of a lot of PUD bookings in the total oil amount in the reserves..

Okay, that makes sense.

So essentially, your PUD oil cut would be in line with your type curve?.

Yes..

Yes..

And our next question comes from the line of Gregg Brody of Bank of America..

You mentioned the 2020 spend would be similar on the D&C side to '19.

Did you -- can you provide some guidance on what the infrastructure spend might look like as part of that?.

I think Rick's got better numbers in -- but effectively, the 2020 is reduced. We've said now for a couple years that our infrastructure spend is basically behind us, but you always have to set tanks and things and time lines. So there is some infrastructure spend.

And that infrastructure spend that we've, in the past, again to repeat myself, has led to us to really have very, very efficient operations and very efficient LOE. I think 2020 will be somewhat similar to 2019..

And then in the following years, I would expect to see it begin to come down. That would be -- '19 and '20 will be some expansion into newer areas, some of the acreage that was acquired where we would be expanding some of our existing corridors.

So as Randy said, '19 and '20, I would expect the infrastructure to be very similar and then begin dropping again..

And I appreciate all the detail here. Just I'm curious about how you're thinking about managing your credit profile as you navigate commodity prices and what you do with excess cash flow? Maybe you can give us an update there, that'd be helpful..

Yes, on the credit side, as you are aware, we have two outstanding long-term note issued. There's $800 million associated with that, none of which is due prior to 2022. We do have our revolving credit facility, which has $1.3 billion borrowing base, of which we've drawn about $200 million -- little over $200 million on that.

The fact that we are dedicated to operating within cash flows, I would not expect to see any meaningful change in that line.

And so with the amount of liquidity that we have, the fact that there is no long-term debt due for three years, we are well below any covenant tests within that credit facility, so we're very comfortable with where we're at today even in a fluctuated commodity price environment..

I appreciate all that.

What I meant more specifically was are you targeting a leverage target through this -- through your plan here? How are you thinking about those types of metrics?.

We've always looked at that and make sure that we had plenty of flexibility. And -- even at times when our -- on a debt -- net debt to either trailing or projected EBITDA was moving up, we had a lot of flexibility of how we could deal with it.

As you saw when we divested of our interest in Medallion and reduced the debt significantly, we think we still have much of that flexibility. But over the outlook for a multiyear outlook, we would be targeting, really, around 2. You may see it move up and be opportunistic to 2.5x, but certainly stay below that.

As I mentioned in my comments, you will see a little bit of an outspend in the first quarter of 2019 and so we would expect to fund that off of our credit facility, but then repay that over the remainder of 2019 such that we would stay at a very similar level to what you see now..

Got it.

And you don't expect the borrowing base to change as a result of the reserve revisions?.

The borrowing base is really based upon the value of our reserves. As you saw, the value has actually gone up versus year-end '17. Since that value is primarily associated with proved developed reserves, that's going to be the primary focus of -- associated with the credit facility.

Now the borrowing base is always going to be determined based upon kind of overriding commodity prices at the time that the group is looking at that and so I think that's going to be dependent upon what is the price deck that the bank group would use.

But at the $1.3 billion base that was really set and approved last fall, there is still cushion to go above that. We chose not to go really push that and I'm very comfortable with that. Now even if it comes down, we would still have more than adequate liquidity given the programs that we're looking at..

And Gregg, keep in mind Rick went over our hedging where on the crude the something, we're floored at 47-something and we get all the upside on that. And that is comforting to us because it does protect to a significant degree our cash flow and line of credit at least through '19..

Great. And then just one follow-up. You gave the 2020 oil production expectations, sort of how it's going to stay flat.

Could you give some insight into how we should think about gas and NGLs in terms of growth?.

On a run rate versus our exit in 2019, yes, we expect to see fairly similar on a BOE basis. We don't have -- we made a breakdown between gas and NGLs, but on a BOE basis that we would again stay pretty flat 2020.

There's always going to be some variability on those amounts on a quarter-over-quarter basis, which is going to be driven by the number of completions that are coming on and when those completions come on in the quarter, as we've always talked about. But on average, we expect that to be very similar and basically flat..

And our next question comes from Noel Parks of Coker & Palmer..

One thing at this point in your development, has the issue of choke management pretty much been resolved? Or is that the thing you're still looking at when bringing the wells online?.

We spent a fair amount of time on doing that and we saw some results that were positive. I think, in general, what we saw was that after some period of time and it was dependent a little bit, quite frankly, on spacing, they reverted back to the mean.

So we still have, and I didn't really address it in my remarks, but we still think we've got efficiencies on the production side, on the completion side, on the drilling side and I think the flow-back process we're still looking at. I don't know what we're going to do choke management across-the-board in any way..

Okay, great.

Just wondering, when you're talking about service costs having seen some improvement, I was wondering specifically as your company decides where you're headed with the rig count, when you're talking with your rig vendors, was there a lot of flexibility? Did they sort of come to the table looking to bargain as far as what you might get for day rates? Or you held onto them, a couple of the rigs?.

It's interesting in that we've had long relationships and I think there's a lot of dialogue between Laredo and our service providers not just on our rigs, but on pressure pumping, on all parts of that. And so I think we've been pretty forthright in explaining where we are and where we're headed. And their job is to take care of their shareholders.

So there's a pretty healthy debate that goes on almost continually. I think it's not a -- we do bid out a fair amount of activity, but that's not a point in time. That's process that goes on almost continually..

One of the, as Randy said, we've -- here, obviously, being very clear about what our strategy is for 2019 to operate within cash flow. So the discussions we're having with our service providers are very much geared towards that.

The more savings we can get, the more activity potentially and so that's just a very ongoing dialogue that we're working hard to have across -- really across all of our services..

Okay, great. And just one last thing, there's a brief mentioned a minute ago about the credit line.

Do you happen to recall what the last borrowing base redetermination, what the price deck was? Where do you stand with the banks?.

Each back within the group is going to use their own individual price deck. That's going to be, the last round, in the fall. Appears to be in the range of $50 to $55..

Okay. They had not gotten as suppressive as sort of the strip we saw at the time, in other words..

Exactly. I'm not going to speak to the banks on what they use because each bank is going to use their own..

And I'm not showing any further questions at this time. I would now like to turn the call back to Ron Hagood for closing remarks..

Thanks very much for joining us today. We appreciate your interest in Laredo, and have a good morning..

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