SilverBow Resources Inc (SBOW) 2017 Q4 法說會逐字稿

Good morning. My name is Felicia, and I will be your conference operator today. At this time, I would like to welcome everyone to the SilverBow Resources Fourth Quarter 2017 Earnings Conference Call. (Operator Instructions) Thank you.

Mr. Doug Atkinson, you may begin your conference.

Thank you, Felicia, and good morning, everyone. Thank you very much for joining us. Joining me on the all today are Sean Woolverton, our CEO; Steve Adam, our COO; and Gleeson Van Riet, our CFO. We posted an updated corporate presentation onto our website, and we will occasionally refer to it during this call, so I 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 measure 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'll turn the call over to Sean.

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

We are pleased to report another strong quarter, closing out what was a transformational year for the company. This morning, I'd like to briefly talk about what we accomplished in 2017 and our plans for 2018.

When I joined the company a year ago, I was often asked why I chose SilverBow. I believe a successful oil and gas company needs 3 foundational theses: assets, finances and people. When I looked at the company, I saw an attractive Eagle Ford position, a clean balance sheet and a veteran team of oil and gas professionals. I knew the foundation was in place to support a successful company, and I was excited for the opportunity to build upon that.

As I think about 2017, I believe we improved on all 3 facets by adding 50% to our Eagle Ford acreage position, significantly enhancing our balance sheet with the second lien notes and adding Steve Adam as our Chief Operating Officer back in November.

Specific to our assets, we added 36,500 acres to our portfolio throughout the year for $50 million. We now have over 100,000 acres in our Eagle Ford portfolio. This new acreage added over 350 future drilling locations. We acquired this acreage at an attractive cost per acre, providing for a very favorable full cycle economics compared to our peers and other basins.

On the financing front, we continue to prudently manage the balance sheet, and in the fourth quarter, we closed on the $200 million second lien senior note. This added liquidity provides for the balance sheet flexibility to accelerate our strategic growth objectives.

In regards to people, we took proactive steps to strengthen our operating team to position the company for an active and successful 2018. Steve has only been with the company a few months and we can already see his fresh ideas and disciplined perspective helping refine processes and implement new technical approaches across the organization.

In terms of operational execution during 2017, our shallow, low-cost, high rate of return drilling program in Fasken and Artesia, combined with our delineation campaign in our southern Eagle Ford gas position, contributed to our 40% growth in volumes compared to the fourth quarter of 2016.

On the cost side, our teams continue to find efficiencies to lower our cost structure, which drove a 35% decline in lease operating expenses.

Much of our focus in 2017 was to build the foundation to become a low-cost operator in the basin. We believe that with the work we have accomplished to date, combined with initiatives ongoing and soon to be enacted, we are well on our way to accomplishing that. Steve will touch on this during his prepared remarks.

In summation, our strong operational performance translated to an improved bottom line, resulting in adjusted EBITDA growth of 90% compared to 2016.

Switching to reserves. We hit the 1 trillion cubic feet equivalent mark on our reserves, an increase of 38% compared to 2016. Our PV-10 increased to $805 million, an increase of 82% over 2016.

Approximately 55% of our reserves are crude undeveloped. We believe our acreage supports multi-Tcfe of upside from here as our year-end 2017 report has minimal reserves associated with our larger blocks at Oro Grande, South AWP and Uno Mas.

Finally, in terms of our 2017 drilling campaign, we are pleased with our results. In addition to drilling our legacy high rate of return Lower Eagle Ford wells in Fasken, we drilled a number successful they are doing the year that significantly advanced our understanding of other areas including Artesia, Oro Grande and Uno Mas.

Given our successful '17 program, we are increasing our activity in 2018 to the addition of a second drilling rig. The second rig will allow us to accelerate our development, unlocking value from our entire portfolio.

So shifting to 2018. This year, we plan to test advanced stimulation designs with multiple ranges of sizes and volumes throughout all areas of our portfolio. Additionally, we are currently testing different choke management concepts, honing in on what pressure management regimes work best in certain areas.

Our drilling program for 2018 is structured to further delineate our Fasken-Upper Eagle Ford position as well as our southern Eagle Ford gas acreage at Oro Grande and Uno Mas so that we can move to development mode in 2019.

On the leasing front, we are very pleased with the acreage we added in 2017, and we continue with our strategic leasing program in 2018 as this provides us with low-cost inventory additions at attractive full-cycle economic returns. We have approximately 10% of our 2018 budget dedicated to this leasing effort.

Beyond our existing inventory, we see additional upside through stacked pay development, including additional landing zones within the Upper and Lower Eagle Ford as well as testing the Austin Chalk. We're still assessing how best to delineate these horizons, and we believe these zones present a large potential opportunity across our assets.

We are very pleased with the resource base we are assembling. Although it is still early days for the Eagle Ford gas play, we believe the play is gaining momentum and our activity in 2018 will go a long way towards advancing the potential of this tremendous resource.

In addition to proving the resource, we are also focused on proof of cost. We need to have a low-cost structure to generate competitive returns with a gas portfolio. We are a margin business and, as such, we continue to take actions to drive our operating expenses lower through a combination of continued efficiencies and cost reductions as well as streamlining initiative, such as the AWP Olmos divestiture set to close today.

This divestiture further streamlines our portfolio and allows us to better leverage our existing personnel while lowering our per-unit lifting cost. You'll see from our guidance, we are targeting lease operating expenses plus transportation and processing for 2018 of roughly $0.64 per Mcf at the midpoint, which we believe competes favorably with any gas play in the country.

So I will close by saying that 2017 was a foundational year for the company. We have in place the assets, financing and people to build a formidable Gulf Coast gas company. For 2018, it's a year where we look to prove the potential of this asset base.

And with that, I will hand it over to Steve.

Thank you, Sean. Moving on to our operational results for the fourth quarter. Volumes in the quarter were driven by strong performance from our production base, especially in Artesia, which benefited from a full quarter's worth of flush production due to a 3-well pad, which came online at late August.

Fourth quarter production also benefited from 4 net wells brought to sales, including 2 in Fasken, 1 in Oro Grande and our first well in Uno Mas. These new wells drove production to 177 million cubic feet of gas equivalent per day for the quarter, an increase of 13.6% compared to the third quarter. After adjusting for the expected Olmos divestiture, pro forma production in the fourth quarter was 168 million cubic feet of gas equivalent.

Looking out into the first quarter of 2018, we are guiding for average daily production of 156 million to 162 million cubic feet of gas equivalent per day. After adjusting for the Olmos divestiture, we are guiding for pro forma production of 150 million to 156 million cubic feet of gas equivalent per day, which assumes a March 1 closing day.

This drop in production from fourth quarter to first quarter reflects the change in the number of first deliveries, frac mitigation management and the impact from the sale of our AWP Olmos properties.

Specifically, as it relates to timing of first deliveries quarter-over-quarter, we brought on 3 net equivalent wells in the fourth quarter of 2017 compared to 1.25 net equivalent wells that we plan to bring on in the first quarter of 2018. As a reminder, the 6-well pad we completed in Fasken during the first quarter only commenced flow back last week.

Additionally, to accommodate this large pad stimulation, we shut in 10 wells during the month of February, representing a reduction of nearly 15 million cubic feet per day. This dynamic of large swings in production going off-line during fracking then surging upwards due to flush production, illustrates the [sawtooth] impact that pad timing can have on quarterly production levels.

Moving on to our new rig. It is designed for being optimally efficient at pad drilling, while our current rig is optimized for drilling the deeper gas areas in our portfolio. We do not anticipate drilling many single well pads this year. We expect to drill another 6-well pads sometime in the second quarter, with production coming online in the third quarter.

For the full year, we are expecting to complete 25 to 26 net wells, which is reflective of the timing associated with pad drilling and the addition of a second rig. Looking out further in the year, we're expecting to see a production ramp that corresponds to our back-end loaded capital budget.

Our 2018 capital program calls for a budget of $245 million to $265 million, 70% of which is for drilling and completions capital. We expect to spend an additional $25 million to $30 million on leasing as well as approximately $50 million on facility and infrastructure spend.

Our infrastructure development continues to advance in Oro Grande and Uno Mas, with gathering systems expected to be installed in the coming quarters as well as other separation, treating and ancillary needs.

Moving on to costs. We are evaluating and critiquing all of our unit costs, processes and procedures for our operation and supply chain functions. While much of our early cost reductions to date have been driven by reductions in saltwater disposal and chemical costs as well as other labor costs, there are significant cost-savings opportunities through debundling and selective aggregation of services along the value chain for both CapEx and OpEx spends.

We are already starting to see results as we reported leasing expenses of $0.34 per Mcf equivalent in the fourth quarter compared to $0.41 in the prior quarter.

We expect our lease operating expenses per Mcfe to decline throughout 2018 due to our Olmos divestiture and the growth in production associated with the second rig. In addition, the AWP Olmos wells carry significantly higher per unit cost than our Eagle Ford asset, so their divestiture will reveal our lower LOE cost on our core Eagle Ford portfolio.

Additionally, adding the second rig to our drilling campaign provides additional scale, which we are leveraging to selectively procure goods and services directly from manufacturers. We also expect to offset any inflation in 2018 with additional efficiencies. For example, we are planning for improved cycle times as a result of adding a second rig to the portfolio.

Our team has done a great job thus far in assessing areas for cost reduction, and we are excited to see what else we can do during the year. Keys to success for us will include improvements in bid selections, vendor performances and rigorous commercial management of our drilling completion and production services.

As I mentioned earlier, we recently completed the 6-well pad in Fasken, which was the largest pad in the company's history. Average well cost for this pad came in under the $5 million type curve assumption and included 3 Upper Eagle Ford wells, which were more weighted towards proof of resource versus proof of cost.

Developing stacked pay at Fasken, including Austin Chalk potential, is a significant opportunity for us as we can leverage the existing infrastructure in place for further area upside. Additionally, we also view testing additional zones at our lowest -- as our lowest cost method of growing added inventory. As such, we are now planning more Upper Eagle Ford tests at Fasken due to the early results in productivity and stimulation.

In Oro Grande and Uno Mas, we have significant thicknesses in the Lower Eagle Ford, including other targets across the entire Eagle Ford section. These thicknesses potentially warrant additional landing zones, which are currently being evaluated. The challenge for us is to appraise and successfully delineate these sweet spots across these multiple intervals.

We are currently evaluating our completion designs, including fluids, spacing, proppant loading and intensities for our southern Eagle Ford gas wells in Oro Grande and Uno Mas. We continue to focus on stimulation designs that further optimize and effectively treat near-wellbore rock volumes as opposed to reaching out with [long frac lanes].

We pumped our second Oro Grande well, the NMC 2H, with considerably less proppant than our first well as we continue to carefully test this area and optimize the balance between the increased costs associated with enhanced frac design and the corresponding increase in project returns from higher EURs. For our 2018 program, we are planning to continue to test a range of stimulation designs and proppant volumes.

Specific to choke management, we are testing our pressure management techniques across our entire position. We continue to assess our managed reservoir pressure initiatives for our Bracken wells, which were drilled in 2017. We believe our pressured management approach at Bracken will provide higher recovery efficiencies and enhance returns.

This said, we are also employing various choke management practices to our wells in other areas of our southern Eagle Ford gas position to better assess value and recovery methods -- and recoveries from these methods.

As Sean mentioned, we reported reserves of just over 1 trillion cubic feet of natural gas equivalent. We believe the position we have assembled supports multi-Tcf upside from where we are today as there are minimal reported reserves associated with our larger acreage blocks at Oro Grande, Southern AWP and Uno Mas.

We like what we have in place in Oro Grande and Uno Mas, with 250 to 325 feet of Eagle Ford thickness and 12,000 PSI of pressure. Thus, we are excited about 2018 and maintain a strong pipeline of projects, including further completion design opportunities, additional step-out wells in newer areas and evaluating additional landing zones across our acreage positions.

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

Thanks, Steve. In my comments today, I'll highlight our fourth quarter financial results as well as our operating costs, hedging program and capital structure.

Production for the quarter averaged 177 million cubic feet of gas equivalent per day, which represents a 13.6% increase from the third quarter, driven by strong base performance in Artesia, including contribution from a 3-well pad that came online late in the third quarter. Fourth quarter production also benefited from turning 4 wells online on or ahead of schedule, including our first well in Uno Mas.

Fourth quarter revenue was $58.7 million, with natural gas representing 79% of our production and 63% of our reserves. Our average realized natural gas price, excluding hedging, was $2.88 per 1,000 cubic feet compared with $3.01 in the third quarter. Our differential was a $0.05 discount to Henry Hub and illustrates why the Eagle Ford is such a great market for selling gas.

Turning to liquids, our average realized crude oil selling price, excluding hedging, was $57.64 per barrel compared with $46.93 in the third quarter. Our differential was $2.23 above WTI due to the fact that we sell off LLS, which currently trades at a significant premium to WTI. Our average realized natural gas liquids selling price increased $2.70 in the quarter to $24.37 per barrel, or roughly 44% of WTI.

Turning to hedging. We added significantly to our hedge book in the quarter and have since then even added a few more hedges. Using our 2018 guidance midpoint of 185 million cubic feet equivalent per day and assuming that same level through 2020, we are 63% hedged in 2018, 41% hedged in 2019 and 23% hedged in 2020.

A disciplined hedging program is integral to how we manage risks, so we plan to continue to systematically adding additional hedges to further protect our cash flows. As mentioned on our last call, we entered into some NGL hedges in the fourth quarter, and in addition, we are now hedging both our LLS and gas differentials to lock in favorable pricing.

Turning to costs. LOE was $0.34 per Mcfe compared to $0.41 in the third quarter, driven by continued compression optimization, labor force reductions at the field level and other cost initiatives that Steve discussed.

For the first quarter of 2018, we're expecting LOE expense of $0.35 to $0.36 per 1,000 cubic feet equivalent, which represents a slight uptick to fourth quarter levels, primarily due to lower volumes. As a reminder, our first quarter cost guidance assumes 2 full months of AWP Olmos in our financials, so we'd expect further reductions going forward as these higher LOE wells exit our portfolio.

The AWP Olmos sale is expected to close today, and has a sales price of $28.8 million with an effective date of January 1. As such, we will recognize all the production, revenues and cost in our financial statement until the end of February, and adjust the final settlement payment downwards by the amount of net cash generated by those assets during these first 2 months.

This divestiture represents 491 wells, with approximately 60% of our well count and 6% of our fourth quarter production, so removing them from the portfolio goes a long way towards cleaning up a lot of noise around our reported results and allows us to leverage our existing personnel across our core Eagle Ford footprint.

Additionally, this patch of wells has significantly higher lifting costs on a per unit basis. As such, our full year 2018 LOE guidance of $0.25 to $0.28 is significantly lower than the $0.39 we reported for the full year 2017.

Transportation and processing costs for the fourth quarter were $0.32 per Mcfe. Adding our LOE and T&P together, we have a total OpEx of $0.66 per Mcfe, which we believe compares favorably to our peers.

Production taxes came in at 3.1% of oil and gas revenues for the fourth quarter, which was a significant decline from the prior quarter, primarily due to onetime credits. Cash G&A of $5 million was up slightly compared to third quarter levels, primarily due to $1.7 million in severance costs related to the replacement of our COO and other adjustments to our officer group.

We're guiding for cash G&A of $4.7 million to $5.1 million in the first quarter of 2018 due to the timing of our annual bonus payments, which always occur in the first quarter. For the full year 2018, we're guiding for cash G&A of $18.1 million to $19.1 million. In total, our strong production growth and continued cost focus drove a $0.35 quarterly increase in adjusted EBITDA to $42 million.

Cash interest came in at $3.2 million for the quarter, an increase from the prior quarter primarily due to higher borrowings under our credit facility. Additionally, our interest expense reflects a 0.5 month of interest related to our $200 million second lien notes, which were issued on December 15.

Our all-in cash operating expenses, including G&A, came in at $1.08 per Mcfe in the quarter compared to $1.24 in the prior quarter. We spent approximately $50 million on capital expenditures in the quarter, including $22 million for leasing and acquisitions.

Additionally, we spent $16 million on transferring our Bay De Chene plugging and [abandoned] liability over to a third party. This [BEC] transaction reduces our ARO by $20.9 million, which is split between $7 million of current liabilities and $13.9 million in long-term liabilities. We record a $16.3 million payable for our obligations under the sale contract, split between $11.3 million in accounts payable and $5 million in noncurrent liabilities.

Under full cost accounting, we do not recognize any gain on the $4.6 million difference between the transaction price versus the ARO liability removed, and instead, we recorded a $4.6 million decrease to our capitalized oil and gas properties.

Additionally, our AWP Olmos sale will remove another $6.2 million of ARO from our balance sheet during the first quarter of 2018. As such, on a pro forma basis, our ARO at December 31, 2017 would be approximately $5 million, which compares very favorably to our 2015 ARO liability of over [$16 million]. We view this low level -- this low liability level as extremely favorable for a company of our size, which further highlights the benefit of our streamlined portfolio.

Our 2018 capital program of $245 million to $265 million provides for 30 to 32 net operated wells to be drilled compared to approximately 18 net operated wells in 2017. Approximately 70% of our budget is allocated towards drilling and completion capital, driven primarily by 13 net wells drilled in Fasken, 7 net wells drilled in AWP and 5 net wells drilled in Oro Grande.

Since our second rig is just getting started and we won't finish completing any wells from this rig until late in the second quarter, we plan to bring 25 to 26 net wells to sales in 2018 compared to approximately 22 net wells in 2017. That said, since the second rig will have a typical startup lag between spudding its first wells, completing them and then turning them to sales, we expect to end 2018 with an increase in DUCs from 6 at the end of 2017 to 10 to 12 at the end of 2018.

We are forecasting average production of 175 million to 195 million cubic feet equivalent per day for the full year 2018. Additionally, we provided first quarter 2018 guidance of 156 million to 162 million cubic feet equivalent per day on an as-reported basis, and 150 million to 156 million on a pro forma basis to reflect the AWP Olmos sale. Our corporate presentation includes updated first quarter and full year 2018 guidance, so please refer to it for our latest expectations.

While the timing of the 6-well Fasken pad and commencement of the second rig lead to some lumpiness on our production for the first half of the year, they set us up for strong growth in the second half of 2018 and well into 2019.

Our liquidity of approximately of $260 million as of December 31, 2017, consisted of $7.8 million in cash and $252 million of availability on our bank credit facility. As previously announced, our fall redetermination concluded with an increase of our borrowing base from $330 million to $370 million. However, our borrowing base was subsequently reduced to $330 million in connection with the grind associated with the issuance of the second lien notes.

The proceeds from our second lien notes significantly increased our liquidity and enhanced our balance sheet flexibility and attractive cost of capital. This flexible capital has relatively benign prepayment penalties, with some minimum hedging requirements which are in line with our prudent hedging strategy and have already been taken care of.

Our strong liquidity and solid balance sheet are a testament to our entire team's efforts, and I'd like to thank our banking syndicate for their continued support during our fall redetermination as well as the second lien transaction.

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 fourth quarter, we were in full compliance with our financial covenants and had significant headroom.

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

Thanks, Gleeson. So to summarize, 2017 was a great year as we positioned ourselves with a lot of momentum to execute on our 2018 objectives. We expanded our inventory through a successful drilling campaign, with successes at every field in our portfolio.

As we think about 2018 and beyond, our goal is to continue 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 operational efficiencies and operate with a peer-leading 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 clean balance sheet that has strong liquidity and a veteran operating team, we are well positioned for strong growth over the coming years.

At this point, I'll turn it back to the operator for the Q&A portion of this call.

(Operator Instructions) Your first question comes from the line of Jeff Grampp.

I was hoping, maybe to start off, if you guys could expand a little bit on some of the commentary on some of these optimization tests that you guys are looking at. Is it more, I guess, just kind of continuing some of the smaller tweaks and fine-tuning that you guys did in '17? Or are there maybe some bigger changes you guys are looking to do? So maybe just a little bit more details there would be helpful.

Yes, Jeff, why don't I start, and then we'll let Steve maybe weigh in as well, as he's brought some good ideas to the table for us. So you think about the large inventory set that we have across the gas fairway here -- and it is really early days, specifically to the Upper Eagle Ford, at Fasken and the large position that we've accumulated kind of in the southern part of La Salle and McMullen. So we wanted to test larger stimulations. We did that with the first well at Oro with 3,500 pounds per foot. Very pleased with the results there. Thought we would test some lower-cost concepts, scaling back stimulations on the next 2 wells in that area to about 2,500 pounds per foot. In light of the some of the early results we're seeing, we think there is a pretty close tie now to the stimulation side, so expect that in these next series of wells that we plan to drill. And we plan to drill a dozen wells in the deeper southern Eagle Ford gas window this year. Probably expect to really go even bigger than the 3,500 pounds per foot and test maybe the upper extreme. And then, of course, trying to weigh that with can we bring the costs down. So that's kind of a general overview, and maybe I'll let Steve talk a little bit more about some of the other things we're doing on the stimulation side.

Thank you, Sean. Yes, we're seeing opportunities across the entire portfolio not just because of its massiveness, but because some of the rock characterization that we're currently having to do in this early phase of appraisal. Admittedly, a lot of this is in appraisal with some delineation and yet no development. Of interest in the stimulation design, it's more than just "more is better." It's a case that we've seen an opportunity that we try to leverage from the lower Fasken, which was in development mode that we were able to successfully say, "Hey, that's kind of on the lower side of what we're seeing in terms of the opportunity." So as we work more towards developing these resources, we've seen success in designs that are 3,500 pounds per foot and looking to go more. With that now, to get into some of the detail, the increased stage density seems to also have a strong effect. And to some degree, it's still a mixed bag as it relates to the clusters. However, we're seeing more and more cluster as it relates to our increased density of stages. Added to that, we've been working with some new diversion technology that's also equally been enhancing to some of the early returns. And then lastly, not in all rock areas but in some of the rock areas, we're finding where some of the faults are calcite-filled, as well as some of the other floor spaces have some calcite filling in them and some carbonated material. As such, we've been introducing some different fluid design changes, some of that being complementary to the use of acid. So that's some of the detail to support just -- more than just "bigger is better."

All right, great. Appreciate those details. And then switching over to some of the stack development tests that you guys referenced. Can you guys maybe give us a sense of what kind of spacing assumptions within the Eagle Ford you guys might be going down to? I guess just kind of given what some other peers have talked about lately would be helpful to kind of get a sense for where you guys are at today and maybe where you're looking to go down to.

Yes. We see -- I'll take that one and I thank you for that question because it's something that's really strong in our chemistry right now because we have so much knowledge with Lower Fasken. But as we work towards these more appraisal and delineation areas, especially with much thicker reservoirs, it's giving us an insight as to what we can do both from our own knowledge as well as looking across the fence to others. So in short, if you fast forward, I probably don't see it being any narrower than 660's end zone same plain, and with the potential for stack configuration to be 330. We are doing some testing in around the 800 to 850 range, and we're bringing those down tighter closer to our 650 on our modeling of our frac modeling designs.

Okay, perfect. That's great detail. And then if I could sneak one more in. In the release you guys referenced kind of going more from seemingly kind of -- I guess, acreage capture was a big theme in '17 to more kind of execution and development. So I was wondering is that I guess more a function of you guys kind of being happy with the inventory levels where they're at now? Or are we seeing opportunities maybe getting a little bit fewer and far between?

Yes, I'll field that one, Jeff, this is Sean again. We are seeing more competition come into the play, which should help the momentum behind it as more operators will be in drilling as well as testing some completion designs. But with that, we've seen competition increase on leasing. We have dedicated about 10% of our budget this year to leasing and we'll be opportunistic. If we see more opportunities on the leasing front, we'll expand that budget if it warrants it. And we are seeing the A&D market heat up, and the Eagle Ford number of packages have come into the market. So we'll be active on the A&D front. So we like the inventory we've assembled. Getting to 100,000 acres was important to us to get to that critical mass, but we're willing to push the size of the portfolio even further if it warrants it, and we can generate bid full cycle returns in growing that.

Your next question comes from Ron Mills.

All my questions have been answered.

Your next question comes from Ben Wyatt.

If I can maybe stay on one of the questions Jeff asked, his last one on the acreage side of things. Just maybe focuses on a gas window. Any acreage adds that you guys do, is it going to be more on filling in kind of where you are? Or are there other parts of the gas window that you guys would go into almost a new footprint of some sort?

Yes. You look at the scale of the Eagle Ford gas fairway going from Webb County all the way up through Karnes Trough, and there's well over 1 million acres there, so we're sitting at around 100,000 acres. Right now, we are focused on building scale around our existing areas. So really Southern AWP, Uno Mas and Oro Grande. If you look from Oro Grande up through Uno Mas, we put in about -- just over 55,000 net acres. So right now, that's where we're concentrated in building more of a consolidated block from that western part of Oro Grande all the way up through the eastern part of Uno Mas. But we have our teams looking really across that entire fairway. And if we see the right opportunity come along that -- putting in another block, we'll do that as well.

Got it. That's helpful. I appreciate it, Sean. And then maybe just another question. As I think about '18, you guys obviously are riding that second rig, going to complete more wells this year. Maybe just trying to gauge confidence you guys have around securing frac crews, completing those wells. Just any kind of color you guys can provide around that.

So thank you for that question as well. One, just in support of the frac crew, we're going to be picking up a second drilling rig that we've contracted. And it's -- both of our rigs are super-spec rigs, so that gives us a lot of fungibility across our asset as I mentioned in the prepared remarks. To support that, Ben, on the frac side, we've entered into not a level-loaded, but we have entered into time slot dedication with a frac provider. And we were able to also have durability in those costs throughout the entire year.

Very good. That's -- I appreciate that, Steve. And then maybe lastly here from me guys. Congrats on the Olmos property. Just curious, is there anything else left to kind of clean up, more wells that you guys can sell with a higher-lifting cost? Or should we kind of think of really it's just driving down cost from the efficiency level from here going forward?

Yes. We really think we're pretty streamlined at this point. Going forward, we have about 300 producing wells, 200 of those are Eagle Ford wells that have been drilled over the last probably 6 to 8 years. So very new wells. The reason our ARO is so low is those don't have to be abandoned for decades. The remaining 100 wells are lower-quality wells, but really intertwined with the portfolio that we wanted to probably keep going forward. We may look to shed some of that, but don't see a really clear-cut way to do that. Those 100 wells currently make up about 1% of our production. So I think we're down to the portfolio that we want to go with and then the only -- the direction that we'd move is to add to it going forward.

(Operator Instructions) Your next question comes from John Aschenbeck.

Congrats on all the recent announcements, really tremendous amount of progress since just last quarter's update. So...

Appreciate that, John.

Yes, sure. First question is on 2018's production profile. Your prepared remarks were really helpful understanding the Q1 sequential production decrease. So just, I guess, looking through the rest of the year, what does your current guidance imply for an '18 exit rate? Gleeson, I think you kind of teased at this in your prepared remarks, but it seems like you should have some pretty significant momentum as you exit the year given the back-end weighted completion schedule.

Yes, thanks. We don't really give out [guidance] rights for a bunch -- rates for a bunch of reasons. But if you kind of look at our first quarter guidance, right, where kind of a pro forma basis, given all the stuff Steve walked through, are going to be kind of down a little bit on Q4. I think, in Q2, you can see us kind of -- probably as we're starting to get the second rig, we're not as impacted by the pad drilling as much, we don't get the benefits from the second rig as much. That said, Q2 is probably around-ish what Q4 would be is what I think. So the growth that we have is really at the back half of the year. So I think everyone else can have some of their own -- what they think is going to happen at the back half of the year. And we're happy to talk with you kind of off-line, but I think the back half will be very strong and that's where all the growth comes in. And then, again, given that we think that's -- well, '19, we're obviously not going out with '19 yet, but it is very back-end loaded, and I think Q3 and Q4 will both be kind of equal the amounts of growth, is sort of the big picture way to think about it. Is that helpful?

That's extremely helpful. So that kind of leads me into my next question. Well, not as exact, if you will. But just looking into '19 when you're kind of expected to transition into that state of cash flow neutrality. I suppose not too long after that, you'd begin generating free cash flow. How do you think of a go-forward plan after that point? Do you begin returning cash to shareholders? Or do you continue to pursue higher return projects in the drill bit and just continually grow?

Yes, sure. I mean, like -- I think as a management team, you're always supposed to put your capital to your highest and best use. And when you're a growing company and you've got a [bunch] of opportunities to invest in high rate of return projects, you're supposed to do that. That's generally what shareholders want. So I think what we're looking as a management team is we live in a volatile commodity environment, always have, always will. And capital markets are a bit volatile, too. So I think the steps we took at the end of the last year, putting in place a second lien to really give us that solid underpinning of financing a 7-year (inaudible) that doesn't get redetermined and then leaving our revolver fully undrawn, gives a lot of not only liquidity, but a lot of financial flexibility. You add on that all the hedges we have, which again, kind of gives a lot of cushion should things get volatile. And then you look at the low cost that really Steve has kind of putting together I think, that sets us up well whether we want to kind of keep leasing and growing and what we think is very attractive place for Eagle Ford. Or if at some point down the road, we want to pay out something to shareholders, we could do that. But again, I think when you're in the growth mode, where we are in our development, I think that's kind of more a big company that has less investment opportunities that thinks about returning capital versus where we are, we've got a very deep bench and a lot of attractive rate of return and inventory projects.

And as stated, if you guys want to give a call with us later, if any analysts want to call us to talk about modeling, we're happy to do that. Because -- happy to give you whatever guidance we can to make sure those are sort of in line with what we think.

(Operator Instructions) There are no more questions at this time.

Okay. Thank you, operator, and thank you, everyone, for joining the call. Have a good day.

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