SilverBow Resources Inc (SBOW) 2018 Q3 法說會逐字稿

Good morning. My name is Kyle, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Third Quarter 2018 Earnings Conference Call. (Operator Instructions) Thank you.

Mr. Jeff Magids, Senior Manager, Finance & Investor Relations, you may begin your conference.

Thank you, Kyle, and good morning, everyone. Thank you very much for joining us for our third quarter 2018 conference call.

Joining me on the call today is Sean Woolverton, our CEO; Steve Adam, our COO; and Gleeson Van Riet, our CFO. We posted a new corporate presentation on to our website and will occasionally refer to it during this call. We encourage investors to review it.

Please note that we may make references to certain non-GAAP financial measures, which are reconciled to their closest GAAP measures in the earnings press release.

Our discussion today will include forward-looking statements, which are subject to risks and uncertainties, many of which are beyond our control. These risks and uncertainties are described more fully in our documents on file with the SEC, which are also available on our website.

And with that, I will turn the call over to Sean.

Thank you, Jeff, and thank you, everyone, for joining our call this morning.

We are pleased to report another strong quarter for the company. Our results demonstrate both the quality and growth potential of our assets. We came into the year with aggressive goals and objectives. And as it stands today, I'm very proud of how our organization is performing.

We continue to execute on our plan to deliver exceptional shareholder returns with an acute focus on production and EBITDA growth while prudently developing and delineating our 100,000 net acre position in the Western Eagle Ford. We are now realizing the accelerated production growth from the addition of a second rig to our drilling program earlier in the year.

Our third quarter production of 192 million cubic feet of gas equivalent per day is up 20% when compared to the second quarter. For the month of October, we brought online 2 net wells, and we expect to bring on an additional 8 to 10 net wells by year-end. The increase in new activity will drive growth for the fourth quarter and into the first quarter of 2019.

On the cost side, we continue to focus on driving efficiencies to achieve a low-cost structure as evidenced by lease operating expenses declining 41% on a per unit basis compared to a year ago. Our drilling activity and cost reduction measures led to adjusted EBITDA of $44.5 million, an increase of 42% compared to the second quarter.

In terms of our assets, we have been active across our portfolio. Our operations team is carrying out several initiatives, which include testing landing targets, high-intensity slickwater completion designs, proppant intensities and further delineation of the Southern Eagle Ford gas fairway. The improved performance of our Upper Eagle Ford development wells in our Fasken area reflect our completion optimization efforts, with the most recent 6 wells exceeding the type curve by 8%. Our latest 2 well pads from our Uno Mas and AWP areas in the Southern Eagle Ford yielded 30-day average IPs of 24.6 million and 29.3 million cubic feet of gas equivalent per day, respectively, with both pads producing at or above their type curves.

Turning to our capital program. We currently have 1 rig drilling in our Fasken and Artesia areas and a second rig focused in our Oro Grande, AWP and Uno Mas areas. Capital expenditures for the third quarter reflect an increased pace in our completion activity. For the year, we are increasing our 2018 capital program range to $290 million to $310 million, which sets us up for a strong 2019. The change from our prior guidance reflects drilling cycle time compression, the testing of high-intensity completion designs and the drilling of higher working interest wells. Steve will provide additional details in the operational section of the call.

From a realization standpoint, we continue to benefit from strong basis pricing in the Eagle Ford. Crude oil and natural gas realizations in the third quarter were 103% and 102% of WTI and Henry Hub, respectively, excluding hedging. To support our multiyear development plan, we remain diligent about layering on commodity hedges to protect the returns as prices dictate.

On the financing front, we recently completed our semiannual borrowing base redetermination resulting in an $80 million increase to the borrowing base under our credit facility. Our balance sheet and debt metrics will continue to be a focal point for us as we move closer to 2019.

Finally on the acquisition front, we continue to see active deal flow and are currently evaluating transactions of various sizes, commodity mix and geographic footprint within the Eagle Ford. While we cannot predict the timing of our next acquisition, we're encouraged by the current activity level and believe there will be opportunities for us to acquire quality assets at favorable prices.

By building on the momentum in the second half of 2018 and continuing to advance our Eagle Ford growth strategy, we are well positioned to carry forward our notable production ramp into 2019.

And with that, I will hand the call over to Steve.

Thank you, Sean. Moving on to our operational results.

Production of 192 million cubic feet of gas equivalent per day in the third quarter was driven by a substantial increase in activity across our portfolio. We brought 13 net wells to sales in the third quarter versus 7 net wells during the first half of the year.

In Artesia area, our 2-well Evans pad averaged 570 barrels of oil per day during the first 2 months after flowback, which drove our out-performance on oil production.

In our AWP area, our recent Bracken wells have displayed higher-than-expected NGL yields at 80 barrels per million cubic feet of gas, which drilled higher-than-expected NGL production. As we close out the year, we expect to bring an additional 8 to 10 net wells in November and December.

For the fourth quarter, we are guiding for production of 203 million to 233 million cubic feet of gas equivalent per day. The given range is a result of extended shutting times in our Fasken area, gathering line delays in our Oro Grande area and timing uncertainty associated with wells waiting on completion. While short cycle times have been a strength for ours, many of the wells that will be turned to production from multi-well pads, which add an additional layer complexity.

During the third quarter, we completed 2-well pads in our Oro Grande, Uno Mas and Artesia areas, a 3-well pad in our Fasken area and the final 3 wells of a 6-well pad also in our Fasken area. The Fasken 6-well pad included 3 Upper Eagle Ford wells and 3 Lower Eagle Ford wells. As a result of a shift to high-intensity completions and other operational improvements, recent wells in our Fasken, AWP, Artesia and Oro Grande areas are all producing above their expected type curves with our Uno Mas area -- while our Uno Mas area is producing at its type curve. We plan to operate 2 drilling rigs for the remainder of the year. Our high-specification rig added in early March will continue to focus on the Western portion of our Eagle Ford portfolio in Webb and Southwest La Salle counties. The other drilling rig will focus on our Southern Eagle Ford and AWP areas.

As for cost, we continue to evaluate and optimize all of our unit costs, processes and procedures for our operating and procurement functions. These initiatives include the use of regional sand in completions, improved utilization of existing facilities, elimination of redundant equipment and replacement of rental equipment with company-owned equipment.

As for sand, we utilized a blend of both regional and Northern white sand on 5 wells during the third quarter and we are looking to further increase our blended usage. We believe that using regional sand is a compelling value proposition, and on a per pound basis, sales was up to 30% from current Northern white prices, while performing comparably in the reservoir.

Lease operating expenses for the third quarter were $0.24 per Mcf compared to $0.41 per Mcfe a year ago, a decrease of 41%. We were able to achieve this through disposition of our higher cost Olmos wells, renegotiating chemical costs, optimizing maintenance activity and a renewed focus on our field labor costs. We expect to sustain our LOE on a unit basis in the fourth quarter due to continued cost discipline combined with the ramp in production from our recent drilling and completion activity.

Turning to capital expenditures. We invested approximately $97 million in the third quarter. A large portion of our spend was related to high-intensity slickwater completion techniques. We have been strategically employing these techniques across our portfolio using slickwater designs on 75% of the total wells completed in the third quarter. Overall, we averaged a completion intensity of 3,100 pounds of proppant and 65 barrels of fluid per foot of lateral, an increase of 51% and 93%, respectively, over the wells completed in the first half of the year.

In the third quarter, we completed an Uno Mas well with 4,500 pounds of proppant and 62 barrels of fluid per foot of lateral, which was our largest fracture stimulation by proppant intensity to date and the largest Eagle Ford frac by proppant intensity in the immediate area. We also completed a 2-well pad in our Oro Grande area with an average of 4,000 pounds of proppant and just under 90 barrels of fluid per foot of lateral, which is the highest fluid intensity we have ever pumped.

Early results from these higher intensity fracs indicate they outperformed the gel-based hybrid style medium intensity completions we have historically used. We plan to employ these completion designs across our portfolio through the remainder of 2018, resulting in a $30 million increase from our prior guidance.

On the timing side, we're optimizing our scheduling and budgeting to take into account the upsized frac operations and extended flowback periods associated with these larger fracs. The medium intensity hybrid fracs typically reach the maximum production rates in 7 to 10 days, while our largest slickwater completions are pushing this out to 14 to 20 days. In addition, we are actively evaluating the value proposition of the larger stimulations and independently analyzing the effects of both proppant and fluid intensities.

Our drilling operations are exceeding our expectations from a cycle time standpoint. We are drilling wells faster and have also elected to drill higher working interest wells in the latter half of the year. As a result, we will be investing an additional $24 million to drill 2 to 3 net wells and complete 3 to 4 net wells, bringing total net wells drilled to 34 to 35 and total net wells completed to 29 to 30 for the full year. The benefit from this increased activity will be realized late in the year and thus will have more of an impact on our 2019 volumes.

While delineating portions of our acreage position and testing new completion designs, we incurred unanticipated costs of $16 million. The majority of these costs were associated with the development of tools and practices necessary to operate in the high temperature and high-pressure environment of the Southern Eagle Ford Gas fairway. Partially offsetting these increases, we were able to reduce $25 million of non-drilling and completion capital expenditures.

The first part of this reduction was achieved through an acreage trade where we swapped 2,300 net isolated acres for 4,300 net acres contiguous with our Oro Grande and Uno Mas areas. In total, this acreage grade added 21 locations at Oro Grande and 14 locations at Uno Mas. The stranded acreage would have required a significant amount of midstream capital in an area where we lack sufficient size and scale. The second part was achieved through continued success of our frac mitigation program. Through preloading offset wells, we have reduced the need to remediate wells impacted by frac hits.

To summarize, our revised 2018 capital program range of $290 million to $310 million incorporates drilling cycle time compression, the testing of high-intensity completion designs and the drilling of higher working interest wells. We continue to test larger sand volumes, tighter stage spacings and slickwater fluid designs across our portfolio and to focus on stimulation designs that further optimize the effective -- and effectively treat near wellbore rock. We maintain considerable flexibility to modify our drilling program based on these results, commodity prices and other strategic opportunities.

Shifting to our operational results. In our Fasken area, we completed the Rio Bravo 1H, 2H and 101H with average lateral length of 6,300 feet. The 1H and 101H were completed using slickwater frac design with an average pad completion intensity of 3,150 pounds and 62 barrels per foot.

Recent Upper Eagle Ford wells are all above their recent type curves. In Artesia area, we completed the Evans 1H and 2H and are very pleased with the results to date. The liquids cut from these 2 wells currently exceeds 55%, and after 80 days on a laterally adjusted basis, they are on average exceeding their type curve by 25%. Given these results, we are currently completing a 3-well pad in Artesia area and expect to bring those wells online in the fourth quarter. We continue to evaluate liquid-rich opportunities in our Artesia area and the rest of our portfolio.

Moving to our emerging Southern Eagle Ford gas area. As Sean mentioned, we have seen strong performance from our Uno Mas and AWP areas. Our ask per wells in these areas have averaged 13.2 million cubic feet of gas equivalent per day during the first 2 months of production after flowback and all are currently producing at or above their respective type curves.

In the Oro Grande area, we completed -- excuse me, we drilled and completed the NMC 5H and 6H. These wells had lateral lengths of 7,500 feet and were completed with slickwater frac designs of 4,000 pounds of proppant and 87 barrels of fluid per foot. Our drilling department has been relentless in working with vendors and consultants to drive down costs and eliminate tool failures. The team employed a higher temperature mud motor and MWD tools as well as improving the whole cleaning efficiency through insights gained from analyzing our previous NMC wells.

As a result of these improvements, our NMC 6 was 30% cheaper and 35% faster to drill than the average of our NMC 1H through 5H wells. On the productivity side, we have just recently brought these wells online, and they're each averaging 13.7 million cubic feet of gas equivalent per day. Please refer to our corporate presentation for a summary of our recent well results.

To recap, the third quarter marked the second full quarter of running 2 drilling rigs. Our production growth is now being realized as wells from our expanded capital activity are being completed and brought to sales. As we shift to the fourth quarter, we are excited about the prospects that lie ahead.

With that, I'll turn it over to Gleeson.

Thank you, Steve. Second quarter revenue was $65 million with natural gas representing 83% of production and 67% of revenue. During the quarter, our realized pricing was 103% of NYMEX WTI, 102% of NYMEX Henry Hub and 45% of NYMEX WTI for NGLs. While NGL prices, particularly ethane, rallied earlier in the year, they have since retreated somewhat. As such, we are now guiding to 32 -- sorry, 37% to 39% NGL realizations for the fourth quarter.

Our hedging loss on settled contracts for the quarter was approximately $4.1 million. We continue to be active with our hedging program and now have approximately 70% of our production hedged for the balance of 2018 based on the midpoint of our guidance. In addition, we have also used oil and gas basis swaps to manage our exposure to differentials. For 2019, we have gas basis hedges of 130 million cubic feet of gas equivalent per day with a weighted average differential of negative $0.01.

Turning to cost. Lease operating expenses were $0.24 per Mcfe, down 41% compared to the third quarter of 2017 and down 8% compared to the second quarter of this year, primarily driven by continued cost reduction initiatives.

Transportation and processing costs for the third quarter were $0.35 per Mcfe, coming in below the low end of our guidance range. Adding our LOE and T&P together, we achieved total OpEx of $0.59 per Mcfe, which we believe compares favorably to our peers.

Production taxes for the quarter were 3.8% of oil and gas revenue due to a favorable ad valorem tax adjustment. Our third quarter figure represents a 27% decrease compared to the prior quarter.

Cash G&A of $3.9 million compared favorably to guidance of $4.9 million due to ongoing efforts to reduce administrative costs. Our all-in cash operating expenses, including G&A, came in at $1.04 per Mcfe in the quarter compared to $1.21 in the prior quarter. Our ongoing efforts during the second half of the year allowed us to achieve a level considerably below our $1.10 target.

In total, strong production and continued cost focus resulted in adjusted EBITDA of $44.5 million in the quarter. Cash interest expense was $6.9 million for the quarter, a slight increase due to increased borrowings on our credit facility.

Looking out in the fourth quarter, we're guiding for production of 203 to 233 Mcfe per day. For the full year, we are narrowing our production guidance range to 179 to 187 Mcfe per day. Please refer to our corporate presentation for complete details of our latest guidance.

Turning to the balance sheet. We had $124 million outstanding under our revolving credit facility at the end of the quarter and our liquidity position was approximately $211 million. We just completed our fall borrowing base redetermination, which resulted in an $80 million increase from $330 million to $410 million. Our strong liquidity position is a testament to the growth trajectory of our asset base, and I would like to thank our banking syndicate for their continued support.

We expect to fully fund our 2018 capital program with cash generated from operations and borrowings on our credit facility. At the end of the third quarter, we were in full compliance with all our financial covenants and had significant headroom.

And with that, I'll turn it over to Sean to wrap up our prepared remarks.

Thanks, Gleeson. So to summarize, the third quarter demonstrates the quality and growth potential of our assets. We are now realizing the accelerated production ramp from the addition of a second drilling rig. Our operations team continues to execute on several initiatives with an intent focus on cost optimization and efficiencies.

Our recently completed borrowing base redetermination provides us with ample liquidity and running room to continue advancing our Eagle Ford growth strategy. As we think about the fourth quarter and beyond, our goal is to grow production by drilling wells with attractive rate of returns and maximizing our margins by leveraging our low operating cost.

We continue to focus on driving efficiencies and operating with a competitive cost structure. We have developed a robust drilling inventory with a substantial number of locations that deliver attractive rate of returns, and we are continuously working to high grade this opportunity set. Along with a veteran operating team and a clean balance sheet with strong liquidity, we are set up for strong profitable growth over the coming years.

And at this point, I will turn it back to the operator for the Q&A portion of the call.

(Operator Instructions) Your first question comes from the line of Ron Mills from Johnson Rice.

A question maybe to start with Steve in terms of the higher intensity completions in slickwater. Your presentation shows the production in each of your areas exceeding type curve and particularly the slide showing the slickwater impact in terms of the uplift. Have you been able to determine in terms of variables, which you think has been the most -- the greatest impact on that improvement? Or is it spread across them? Or is it just still too early to tell?

Thank you, Ron, for the question. The short answer is, still too early to tell. We're testing. We do think there is a relationship between the amount of proppant and the amount of fluid being pumped. And right now, we think we're testing those various sizes on the proppant and we kind of think we're seeing where the larger ends are coming into play. We really haven't seen any diminishment in terms of more fluid being pumped, certainly in our Southern Eagle Ford area where we have a lot of delineation room ahead of us. So right now, we're looking more and more towards fluid intensity and we're continuing to test the various proppant sizes.

And Ron, this is Sean. I'll just layer on to that, that again, we have a lot of runway in front of us. So we're trying to optimize those variables. We think we're seeing the -- we are seeing significant improvement in the well performance. As we think about 2019, we'll really start to try to optimize those variables. We are seeing a softening in completion cost, so it's beneficial to us where we're at in our development to test these ranges. And really we always think about every investment dollar, is it adding returns. So we're going to continue to be relentless as we think about our completion designs and it's all around the returns.

Great. And then, the move to 2 rigs over the course of the last 9 months, you've really kind of delineated and improved productivity across the other half of your acreage outside of Fasken. Do you think in terms of the other areas like Fasken is -- you've now kind of proven up the Upper Eagle Ford to go along with the Lower. There is opportunities for multi-zone development in the other areas and to make sure you don't include any incremental zones in the other areas, correct?

Yes. This is Sean again. You're correct. Our focus on stack pay testing and now development has been in the Western part of our asset base. In terms of the areas over in the La Salle and McMullen, it's early days still. Our drilling thus far has been in a single Lower Eagle Ford level. We're just starting to think about testing other zones. And that area is the thickest part of the Eagle Ford. So we have areas pushing 300 foot of thickness. So we're confident that there is upside to our inventory. It currently just reflects a single zone in our Southern Eagle Ford portfolio. So we think there is plenty of room to run there and excited about what we're seeing in Fasken. And I think we can explore what we're seeing there to our other areas.

Okay. And then maybe this is one for, I guess, Gleeson from an activity standpoint and CapEx standpoint. I know with the higher CapEx, that should lead to higher productivity as we look it through 2019. But even with a higher CapEx level, are you guys still on track to kind of get to that free cash flow neutrality position sometime in the early part of 2020?

Yes. A good question, Ron. I think we're still sort of there thereabout. As Steve and Sean have mentioned, I think the benefits of the increased completion intensity we're seeing are better well performance, which is really good. So while we -- it's early for us to kind of put our 2019 budget, and we're working on our budget scenarios with our board. I think when we look at kind of running kind of 2 full rigs for a year, you sort of take that as the base case and what we can get to with just using kind of the strip pricing. I feel pretty good, 2020 is somewhere in there as we kind of get cash flow positive. And the nice thing from what I look at from a CFO standpoint is with the balance sheet we have now and the growth you've seen in our RBL, of where our leverage stats are and kind of what we could do with kind of more certainty if we wanted too, we were fully funded to cash flow positive at the current capital position. So for us, the only way we'd ever have to go to Wall Street is if we had something good to announce, be it our continued success in our newer areas and raising capital to kind of run a third rig or success from the acquisition front we look at. So from our standpoint as a CFO, that gives me kind of great comfort to when I think about our capital position relative to our spend.

Next question comes from the line of Jeff Grampp from Northland Capital Markets.

Maybe to delve a little bit or ask a little differently than Ron's last question, I know you guys are still putting together final budget and everything for '19. But as we kind of think about CapEx, is there anything if we just kind of take the back half '18 run rate maybe, would that be a plus or minus good ballpark to think about? Or would there be any meaningful kind of puts or takes on that relative to how you guys are seeing potential scenarios for '19?

Yes -- no, I think for 2018, we are going to end up running 1.75 rigs across the full year with the second half of the year being a 2 rig pace. And our current view of '19 is to continue on that pace. So yes, I think as a proxy for 2019, the second half of '18 is appropriate.

Okay. Great. That's helpful. And as you guys are kind of continuing to optimize the completions going forward here, do you guys have generically maybe when you think you're in a better position to definitively conclude on kind of medium versus high intensity if you're getting that incremental ROI on the CapEx? And maybe in the interim, can you just talk about how you guys are continuing to balance maybe your base case completions versus these higher intensity ones?

Yes. So what we're seeing in terms of the higher intensity fracs over the first plus or minus 60 days of production that we have is higher rates, rates that we've held at pretty constant level on those wells. We continue to manage our chokes appropriately. So what we haven't seen is a decline yet. We're seeing pressures that indicate to us that we're contacting more reservoir and at their support there. So the uncertainty in the value proposition is a higher intensity frac is when do we come off decline and at what decline rate do we come off at. All indications for us is that we're adding reserves and so we're just going to have to assess that. For now, we're planning on sticking with this higher intensity completion design, so maybe through probably the next 6 months before we make a decision to maybe dial back or not. And I think what we're excited about is the softening in the frac market is going to allow us to test these designs at probably some lower cost in the early part of next year versus what we've been doing this year.

Yes. And the only thing I would add is, we continue to customize the rock characterizations across the different parts of our portfolio, the experience level of our team, we continue to customize these completions relative to the various rock properties.

Your next question comes from the line of Neal Dingmann.

My first question is for -- just looking at Uno Mas well, you guys talked on that. It was interesting that you're now drilling about 4,500 pounds per foot at that. I know you mentioned earlier in the comments, it's all about return. Is the factor on that sort of twofold: one, you're not only seeing the higher returns when you throw that kind of proppant at it; but number two, now that the cost of that has come down, can you just talk about what you're seeing from something like that? And could that be more -- become more of the norm?

Yes. I think what we're seeing is higher IPs. We're modeling that ultimately we're going to see higher recoveries and higher EURs from those wells. Early last year when we came out with type curves for the deeper gas area, we put out there 3 type curves ranging from 11 Bcf up to 14 Bcf. We're about a dozen wells in. The last 4 to 6 wells are more of this higher completion intensity. Those wells thus far are tracking closer to the 14 Bcf versus the 11 Bcf. So yes, I think we have probably another 6 months or so to kind of watch performance of these higher intensity completions to see if production is declining at a lower rate than the medium intensity, and I envision that we're going to probably look to revise our type curves or maybe even go down to a single type curve for the area that's more in the higher side of that range of 11 to 14.

Very good. Very good. Okay. And then looking at that Slide 13, could you talk about -- looking at the Southern Eagle Ford, do you believe now at this time that you have delineated? I mean, you guys have just done a tremendous amount of work there that's obviously noticeable. Do you think most of the delineation now is done at this point, or is there still some more to do? I'm just wondering now, are you going to sort of, because of that, build or take it sort of to the next level or, I guess, simply do you have more delineation to do? How do you look at it?

Yes. We feel like -- so if you think about that area encompasses for us 60,000 net acres. But it, from a distance standpoint, spreads across 3 Texas counties. So it's still a large area. We've put about a dozen wells in there. We've been focused currently on Oro Grande and Uno Mas. We haven't put wells into the Southern AWP area. So I think there is still delineation for us to work on. We're definitely way further ahead than we were when we started this. We feel like we're now gaining a good feel for consistency. The last 6 wells that we drilled for on Slide 13, 2 that just came on Oro Grande are all in that 14 million a day IP range. So we're seeing some consistency across the whole area. Where you say when do you go to development mode, I still think we still have to test stack pay potential, we still want to optimize further our drilling and completion activities. So we're not quite yet to the development phase. I think that it's probably still another year out when we say, "Hey, let's go all in and really start developing this area out," which is pretty exciting for us in that there is probably 4 to 5 Tcf plus of resource potential here. And so we think the runway is quite significant. There is opportunities to look at midstream as we think about developing this area as well. So we're really starting to think about what that next step is, how we fund the development of it as well bringing in a partner, getting another rig in the area. So early days still, but we think that we're on the right track.

Your next question comes from the line of Ron Mills from Johnson Rice.

One more question that I wanted to ask. I know when you moved to the second rig, your second half activity level significantly is increased with 12 to 15 wells being placed online. With 2 rigs, what do you think a more normal cadence of placing wells online? I know you had kind of built up some ducts early. Just trying to think about that completion cadence and as it relates to the kind of sequential growth you've delivered in the second half of the year to think more about '19 on my end.

Yes. I think for the second half of the year, we're going to be bringing on plus or minus 20 wells. So I think that's reflective of 2-rig activity. So probably closer to 40 wells a year.

And you expect that to be pretty evenly spread?

Across the portfolio?

Yes. Sort of.

Quarterly and timing-wise and across the portfolio. From a capital perspective, it's going to be chunky as pad development -- that's part of pad development. Across the portfolio, that's probably the variable we have. The deeper areas are more like 25- to 30-day wells, where the shallower areas are more like 8- to 10-day wells. So if we move rigs into certain areas over a period of time, the well count might go up or vice versa go down a little bit, but our plan right now is to run the 2 rigs like we have been, one in the deep area, one in the shallow, which was what we've done in the second half of the year, and that's why I think second half well count is a good proxy for a full year 2-rig program.

And I assume coming off of some of the flushness of the third and fourth quarter completions, the kind of 15% to 20% sequential growth we've seen in the back half of this year will come down a little bit, but are you still expecting a more -- at least a more consistent or a level of sequential growth through all of next year?

Yes. Yes. I think in the second half of '18, we're going to see production growth in the plus or minus 35% range. And as we think about 2019, I think full year growth in that range is probably a good estimate. So from a quarter-over-quarter sequential growth, it will come down, but the second half of the year will probably be a good proxy for the full year growth in '19.

(Operator Instructions)

Kyle, I think it looks like there's no more questions. So I think we can conclude our call for today. And I appreciate everyone dialing in and your interest in SilverBow.

This concludes today's conference call. You may now disconnect.

Okay. Thank you.