SilverBow Resources, Inc.

Thank you, Amber, and good afternoon, everyone. Thank you very much for joining us.

Joining me on the call today are Sean Woolverton, our CEO; Bob Banks, our COO; and Gleeson Van Riet, our CFO. We posted an updated corporate presentation onto our website, which we will refer to 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 now turn the call over to Sean.

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

We'll start this afternoon with Slide 3, our company overview. Many of you are already familiar with the company.

But for those of you who are new to the story, this slide provides an overview of our assets. As you'll see, our operations are focused exclusively in the Eagle Ford Shale, with our 63,000 net acres [ straggling ] all 3 hydrocarbon windows in the basin.

Our Fasken area in Webb County underpins our operational expertise. We have drilled some of the best gas wells in the entire Eagle Ford there and look forward to leveraging that expertise across our portfolio.

Our most recent estimate of drilling locations is about 378 gross locations across our core acreage, providing nearly 13 years of inventory at our current 1-rig pace. We also have upside potential and additional down-spacing in the Eagle Ford as well as we have opportunities for stack laterals in the Upper Eagle Ford.

And we have potential development in the Austin Chalk across certain parts of our acreage.

On Slide 5, we provide a quick up-to-date overview of just some of the work that has been done over the last year or so to position the company where it is today. I'd like to briefly go over a few of those items.

We have exited our position in Louisiana and are now a pure Eagle Ford company. Through extensive rightsizing and operational cost structure initiatives, we have reduced our G&A and LOE cost by 55% and 60%, respectively, since 2015.

We have renegotiated key T&P agreements and mitigated our once burdensome midstream contracts. The company went through a smooth and successful restructuring, converting nearly $1 billion of debt to equity and removing over $100 million of P&A liability from our books through noncore asset sales.

We recently redetermined our RBL that provided the necessary liquidity to announce our expanded budget announced just last week. The company has put into place a thoughtful and disciplined hedging strategy, with 75% and 44% of our anticipated natural gas and oil volumes hedged for the remainder of 2017, using the midpoint of the guidance.

We recently rebranded the company in conjunction with our relisting on the New York Stock Exchange. We are now operating as SilverBow Resources to recognize a clear break from the past and are excited where the company stands today, and we're excited about the path forward.

Our ticker is now SBOW.

Additionally, we have added 3 members to the executive management team, including myself; Gleeson Van Riet, our CFO; and Chris Abundis, who has been with the company 12 years, was recently promoted to General Counsel. My first priority as Chief Executive at the company was to bring together a leadership team that exemplifies our core values and culture, with an [ a line ] focused on strategy and execution.

This leadership team uniquely embodies what I believe to be the foundation of the company, specifically, operational excellence, disciplined financial management and the promotion of human capital. So as you can see, the first several months of 2017 have been busy yet transformational for us.

Jumping to Slide 13. We provide some highlights for the first quarter.

Our net production was approximately 136 million cubic feet of gas per day, with 83% of that being natural gas and 10% natural gas liquids and 7% oil. Our development activity for the period was primarily focused in Fasken, where we completed 4 wells that were previously drilled in the fourth quarter '16, and drilled and completed 5 more wells that went to sales in April.

Late in Q1, we moved the rig that we have under contract to our AWP area in McMullen County, where we drilled and recently completed 2 wells. These will be the first wells in AWP since bringing on 4 wells in that area in mid-2016.

The wells recently went to production, and we like the results we're seeing and look forward to sharing more on their performance during next quarter's call.

As we look out for the remainder of 2Q, we are drilling our first well in our Oro Grande lease position. This position is located in Southeast La Salle County in the dry gas window.

We have approximately 25,000 acres in the position, thus far. We have reached total depth on the well, currently running [indiscernible].

Completion operations are -- will be underway soon, and we expect to bring that well to sales in the third quarter. We are excited about the potential there, and Bob will talk more about that well and what we're doing in the area.

We are in the process of moving that drilling rig into our Artesia area located in Western La Salle. This is a liquids-rich area, and we have 2 well pads there that we'll be drilling in the quarter.

Moving over to Slide 8. We feel like every well we bring online is better than the last.

Our team does a great job of learning something new from each well we drill and applying those learnings to the next well. It is our culture that fosters innovation and entrepreneurship and has resulted in the company drilling 12 of the top 15 gas wells drilled in the Eagle Ford.

We look forward to taking this knowledge set and technology to new areas of our portfolio in 2017. On Slide 14, we refer to our guidance for the full year.

Given our solid financial position as well as the strong assets -- the strong returns our assets generate at current prices, we elected to keep the high-performance rig operating through the remainder of the year. As previously announced, we anticipate spending $190 million to $200 million for the full year.

We believe this level of activity should generate average full year production in the range of 145 million to 155 million cubic feet of natural gas equivalent per day. This program will yield solid growth in production throughout the course of the year and will give us momentum entering 2018.

We are experiencing some inflation pressures on our services as is the rest of the industry. We will, of course, be very disciplined in our spending and watch our returns closely.

Our asset base provides us with the flexibility on our spend as we have a large percentage of our acreage held by production. Our focus will be growth and returns.

To that end, we have been active in building our hedge position over the past 60 days, and we will continue to layer on incremental hedges to protect our revenue as price warrants it. Bob will go into further detail about our budget and drilling schedule for the remainder of the year.

Moving to Slide 11. This slide demonstrates the improvements we have made to our cost structure and is a testament to the dedication and efforts of our team members, both in the home office and in the field.

This slide also illustrates our LOE per Mcfe compared to 11 of our peers as well as where we plan to be on average for the full year. So you can see from this chart that we are a top-quartile producer in terms of lease operating cost.

We have been able to improve upon our unit LOE cost during the downturn despite a decrease in production. We expect our LOE cost structure to become even more competitive as we ramp up and execute on our growth strategy.

The bottom chart on this slide shows the improvement we've made on G&A. Headcount has been reduced by 58% since 2016.

And we relocated our new headquarters to West Houston for more favorable rates and smaller footprint. As with LOE, our goal is to be a top-quartile performer on G&A unit costs, and we will see improvement in this metric as we move forward and as we grow the denominator.

The last topic I want to [ touch ] on before turning the call over to Bob is to provide you with a little color on what we are doing to expand our asset base. We are committed to the Eagle Ford at this time, and we believe there are multiple pathways to grow our position in the play.

For starters, we will allocate approximately $25 million of our budget to leasing and are already adding to -- acres to bolting on positions in and around our fields. We will continue to do the blocking and tackling on the leasing front, as this will add high-quality locations to our inventory.

Having said that, some larger packages in the Eagle Ford have surfaced over the last few months, and we expect even more to come to market as the year progresses. We are doing our due diligence in understanding what would or would not make sense for the company, and how we want to position ourselves, going forward.

We will be opportunistic on the acquisitions front, but we will be patient in waiting for the right opportunities.

I'll conclude by reiterating that our focus is to concentrate our efforts within our portfolio where we see considerable growth potential and impressive returns. We will look to grow our long-term drilling inventory through leasing and through accretive acquisitions.

And finally, we believe that accelerating our drilling in the back half of 2017 is an excellent use of capital and will provide the platform necessary to generate meaningful growth this year and beyond.

With that, I'll hand the call over to Bob.

Thank you, Sean. Our total net production for first quarter '17, 135.6 million cubic feet equivalent per day, was driven by accelerated performance at Fasken where we brought 9 wells online ahead of schedule.

With these and other efficiencies, we feel like we're on track to achieve our production guidance for the 145 to 155 million cubic feet of natural gas equivalent per day for the full year. Our development activity for the period was primarily focused in Fasken, where we completed 4 wells that were previously drilled in 4Q '16 and drilled and completed 5 more wells that went to sales in April.

Net production for Fasken in the quarter averaged 89 million cubic feet of natural gas per day, which represents 65% of our total production. Net production from Fasken is currently running above 96 million cubic feet of gas per day.

The company's drilling and completion well cost in Fasken, excluding location, tubing and facilities, decreased 25% to $4.3 million compared to $5.7 million per well for the prior drilling campaign in the same area. A significant amount of the company's recent well cost reductions are attributable to process and design improvements, resulting in a new technical limit set in Fasken as the 57H was drilled in a record 5.7 days spud to TD.

We continue to evaluate the potential we have in Fasken with respect to the Upper Eagle Ford and the Austin Chalk. We have one Upper Eagle Ford well that was completed in 2015 that we booked at a 10 Bcf EUR.

That well was drilled and completed with older technology, and we don't believe it represents the true value of the Upper Eagle Ford there. We have been testing newer landing points, frac designs and scale inhibitor methods for the Upper Eagle Ford and are encouraged by the potential uplift these changes can make.

We tested these concepts in the last well drilled at Fasken before moving the rig. This well, the Fasken 63H, was drilled as a hybrid well, with a portion of the lateral in the Upper Eagle Ford and a portion of the well in the Lower Eagle Ford.

This well is currently being tested and is performing as good as the surrounding 100% Lower Eagle Ford wells. We'll continue watching this well to explore the possibility of bringing the rig back to Fasken later in the year to further evaluate the Upper Eagle Ford.

Over in AWP, our production for the quarter was 35 million cubic feet of natural gas equivalent per day. The production mix out of AWP consisted of 51% gas, 27% natural gas liquids and 22% oil.

Drilling and completion costs in AWP, again, excluding location, tubing and facilities, which are pretty well set, decreased 16% to average 6.4 million for the last 2 wells compared to an average of 7.6 million associated with the last drilling campaign in the same area. We recently drilled and completed 2 wells in AWP and brought those wells to sales in late April.

These wells are currently on flow-back and are being tested under a managed choke evaluation study. The wells are cleaning up nicely, and after cleanup, we expect them to be put into the production system at rates between 9 million and 12 million cubic feet of natural gas equivalent per day.

Plans in AWP for the remainder of the year calls for 6 additional wells in our oily acreage in Northern McMullen County. As Sean alluded to, we are experiencing some inflationary pressure on our services as is the rest of the industry.

Admittedly, with this comes some pressure on pricing and on quality control. We are being very disciplined in our spending and watch our returns closely.

We feel one of our competitive advantages with respect to these issues confronting our industry is our track record as a long-term operator in the region and the strong relationships we've fostered with our vendors over the years. Additionally, the size and scope of our capital budget and the fact that we're running 1 rig in 1 basin allows us to be very precise with our scheduling with dealing with our vendors.

Moving to Artesia. The company produced 11.3 million cubic feet of equivalent gas per day net production during the first quarter.

Production mix there consisted of approximately 46% natural gas, 38% natural gas liquids and 16% oil. We have not drilled in Artesia since 2013 and are very excited to be returning to this area in May.

We plan to drill 7 wells in Artesia during 2017 and think that our newest technologies and designs will yield very favorable results.

As Sean mentioned earlier, we did move the rig over into Oro Grande in April, and have now TD-ed our first well at a little over 20,500-feet measured depth after drilling a 7,500-foot lateral. We will be competing this well in the coming days and expect to turn this well to sales in the third quarter.

Oro Grande, as you may know, is in the dry gas window of the Eagle Ford, similar to Fasken. But unlike Fasken, we plan to test this area with much larger fracs, increasing our sand concentrations up to 3,500 pounds per foot across almost 40 stages.

This area will also have different stage, spacing and cluster design than what we do over at Fasken. The Eagle Ford is a very thick section here, and we're building our frac designs to maximize frac height and stimulated rock volume.

We'll have more to report on our results here in the coming months. Our plans over at Uno Mas call for an initial well later in the year.

On the strategic front, as Sean mentioned earlier, we are using our base of knowledge and our large volumes of subsurface data in order to high-grade and bolt on lease positions to our existing acreage in order to expand our drilling inventory for continued growth into the future.

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

Gerald

Thanks, Bob. If you're following along on our corporate presentation, I'll refer to Slide 13 to hit some of the key points of our first quarter financials.

Total oil and gas revenues for the quarter were $42.4 million, with 73% of our revenues being derived from gas sales. Importantly, this is the first full quarter results without the Louisiana operations we sold last December.

This should be a relatively clean quarter from which to build our guidance going forward.

Price, risk management and other provided a benefit of roughly $10.8 million, which primarily reflects the unrealized noncash change in the value of our hedged portfolio due to lower oil and gas prices at quarter-end. Our realized hedge loss on -- our realized loss on hedge settlements during the quarter was $700,000 in cash.

Our average realized natural gas price, excluding the effect of hedging was $3.07 per Mcf, compared with $2.86 in the fourth quarter of 2016. Our strong gas realizations illustrate why the Eagle Ford is such a great market for selling gas.

In addition, the Eagle Ford has significant existing midstream infrastructure and benefits from close proximity to the major demand centers of the Gulf Coast petrochemical industry, an expanding number of LNG facilities and a growing Mexican export market.

Turning to liquids. Our average realized crude selling price, excluding the effects of hedging, was $49.26 per barrel in the first quarter of 2017, up from $47.10 in the fourth quarter of 2016.

The average realized natural gas liquids selling price for the first quarter of 2017 was $20.33 per barrel, or roughly 41% of WTI price versus $18.84 per barrel in the fourth quarter of 2016.

Moving to cost. Net G&A for the quarter came in at $9.8 million due to a number of onetime charges.

Removing our noncash comp expense of $1.5 million, our actual cash G&A for the quarter was $8.3 million, which was inflated due to a number of one-off severance and moving and other costs related to our January move and reduction [ in force ] as well as an accrual for estimated bonuses. On our guidance slide, we show a more normalized G&A estimate for the second quarter of $4.7 million to $5.1 million, along with a full year 2017 estimate of $22 million to $24 million.

Our LOE for the quarter came in at $5.8 million or $0.47 per Mcf, and when added to our transportation processing fees of $4.4 million, we have a total cost of $0.83 per Mcf, which we believe compares favorably to our peers. Adjusted EBITDA, a non-GAAP measure that is reconciled in the appendix of the presentation, was $21.5 million.

And our costs incurred for capital expenditures for the quarter were $32.8 million, approximately 85% of which were for drilling and completions activity.

Finally, net income for the quarter was $17.7 million or $1.57 per diluted share, which includes the unrealized noncash gain on our derivative portfolio of $10.9 million.

Moving on to financing. In January, we raised $40 million in equity to repay the nonconformities of our old RBL which significantly reduced our interest expense.

And then as Sean mentioned, we completely refinanced that facility in April after the quarter ended.

JPMorgan led the facility and was joined by a syndicate of 11 other banks, including 6 new lenders. They increased our borrowing base by 32% to $330 million from $250 million previously, reduced our interest rates, and we also adjusted our credit agreement to current market terms.

The net effect of all these actions, which drive our liquidity higher to approximately $150 million as of May 1, while at the same time reducing our quarterly interest build to a very manageable $2.5 million. We were significantly oversubscribed during that process, which was gratifying since we really wanted to find a group of banks that wanted to partner with us and wanted to support our growth.

We believe we did that. We value our relationship with our banks.

And we thank them for their support.

Moving to Slide 27. The credit facility is the only debt we have [ as a ] company due to a very straightforward capital structure of bank debt and public equity.

We expect to fully fund our 2017 capital program with cash generated from operations and borrowings under this credit facility. Looking forward, we recently increased our capital program to between $190 million to $200 million for 2017, with about 73% of that allocated to drilling and completions.

This accelerated program represents a doubling of our prior budget and provides for 26 completed wells that will drive 20% to 25% production growth from Q4 2016 to Q4 2017.

On Slide 14, we summarized the impact of that program on our second quarter and full year 2017 guidance. Starting with second quarter of 2017, we expect 138 million to 144 million cubic feet of natural gas equivalent per day of production [ with ] about 85% gap.

For the full year, we expect an average production rate of 145 million to 155 million cubic feet of natural gas equivalent production per day, which will have a lower gas component of around 80% due to several AWP and Artesia Wells coming online in the back half of the year. Wells from our oily acreage in AWP North produce around 77% oil and 11% NGLs, while Artesia wells produce around 23% and 32% NGLs.

For our realized prices, we expect company-wide to see about $2 to $2.75 differential off WTI and $0.05 to $0.10 off [ Henry Hub ] for natural gas pricing for the second quarter. Similarly, we're reducing our guidance for LOE and transportation -- Sorry -- Similarly, we are guiding for LOE and transportation processing expenses to be in line with first quarter.

As far as production ad valorem taxes, we're guiding for 4% to 5% of oil and gas revenues for both the second quarter and the full year. I've already touched on G&A expenses and interest.

I'll switch to DD&A where we realized $0.80 per Mcf in the first quarter and are guiding to $0.80 to $0.85 for the second quarter and $0.80 to $0.90 for the full year.

Moving to hedging. Hedging is very important to us, so I want to briefly discuss our hedge portfolio on Slide 29.

We primarily use swaps in colors and currently have about 90 million cubic feet per day of gas hedged for 2017 and 40 million cubic feet of gas hedged for 2018 and are just starting the latter end of the portion of 2019.

On the right side of the slide, you'll see our oil hedging. Through the remainder of this year, we have our hedges covering approximately 990 barrels per day of production and another 427 barrels per day of production in 2018.

Together, using the midpoint of our full year 2017 production guidance, on an MBoe basis, we're about 64% hedged for this year and roughly 30% for next year, which protects our cash flow as it supports our drilling program. Full details of our hedge portfolio are contained in our 10-Q, and I would expect to see us continue to layer on additional hedges in the coming months.

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

Thanks, Gleeson. So to summarize, we have a high-quality acreage position consisting of 63,000 net core acres centered around the gas, condensate and oil windows of the Eagle Ford Shale in South Texas.

Our current inventory of over 370 locations provide a runway for organic and economic growth. As Bob mentioned, however, we are actively exploring ways to increase our inventory and have been successful in bolting on positions adjacent to our existing footprint in the basin.

Our operations team is focused on efficiency, cost control and maximizing return. Our goal in 2017 is to demonstrate the ability to grow production by drilling wells with attractive rate of returns and maximizing margins by leveraging our low operating costs.

Along with a clean balance sheet, simple capital structure, minimal debt and strong liquidity, we are well positioned for a strong growth over the coming years. And with that, I'll turn it back to the operator for the Q&A portion of the call.

Maybe we could start in Oro Grande, and that first location. Can you talk us through a little bit how you picked that both geographically, and also if I remember correctly, it's a little bit thicker than down in Fasken, how you picked where you wanted to land that first lateral to kick off the program?

Yes, well, this is Bob. Let me take a crack at that.

We do have offset wells in the area, and one of the wells, the common resources, [ new aces mineral ] 20 was a pilot well with a full core. So we have good well control, we have good core.

We're part of the core lab, core consortium, so we took that core and analyzed it very extensively. This is a very thick section of the Eagle Ford.

This has about 220 Bcf of gas in place. Where we position this well, really, is a result of our 3D data set, which we have encompassing the area, so we tied all of our seismic and inversion work back to these logs and course and created what we felt like was the optimum landing zone that, as you look at the offset wells that were drilled back in 2010 time frame, I believe, we've gone back and looked at how those wells were drilled.

One of the wells was virtually 0% in zone as we would call it today. The other well was maybe 40% to 50% in zone as we would call it today.

Those wells were 4,000-foot laterals, very small frac jobs. Maybe 4 million to 5 million pounds of proppant.

So what we've done is we've used all the technology that we've developed, along with our 3D data set to find the best landing zone. We steered that well, 7,500 feet in the landing zone.

And now we're getting ready to complete it with a completely different approach that would've been done back in 2010. So that 4,000-foot lateral, where maybe 80% more lateral length now than was drilled back then.

And in terms of proppant, we're going to pump about 26 million pounds of proppant versus maybe 4 million to 5 million pounds before. So we think we have a very good handle on this area, it's just a matter as to how effective we'll be with this frac design and getting good recovery factors.

Okay. And it's probably a little bit early, but was there one landing zone that really jumped out?

Or do you think that this could also turn into sort of an upper-lower concept like what seems to be going on in Fasken?

Yes, that's a great question. We actually ran about 40 frac models in this area, and we think there is more than one landing zone that would work effectively here.

So it could be that, ideally, we'll be very effective with the one lateral over this very thick interval and yet very strong recovery efficiencies. But even if we don't, I think it does set up nicely for a potential future wine rack kind of development.

Okay, great. And sticking with the wine rack concept and hopping back down to Fasken.

But the 63H you talked about in the prepared comments, am I remembering it right that it was about 6 stages in the Upper? And if you could talk about kind of where you get the confidence in the Upper.

I mean, did you have some sort of chemical signatures that you could trace whereby you sort of know which stage is contributing which?

Yes. Another good question.

First of all, the Upper Eagle Ford and Fasken, the good thing is we drilled a lot of Lower Eagle Ford wells, so we have logs through the whole area. Every part of Fasken is covered with logs through the Upper Eagle Ford.

So we understand it very well. It's a very quiet area, not a lot of movement.

Yes, you're right, we had the chance with this well to do a hybrid because of well configuration. So about 6 stages were done in the Upper Eagle Ford and about 18 stages were done in the Lower Eagle Ford.

We have used chemical tracers. We're taking gas samples.

And both the chemical tracers and gas samples tell us we're getting contribution fully from each one of the stages because the Upper Eagle Ford has a different signature. We also designed that Upper Eagle Ford test to get into the lower bench of the Austin Chalk.

We're also seeing contribution from the Austin Chalk on tracer. And so we need a little more time to analyze all the data.

But this is kind of how we're setting up our next round of maybe doing a little bit of a wine rack development later in the year.

That's wonderful. And I just have one more kind of a modeling question.

It looks like you got the $5.4 million cost in the back of the presentation for the Lower Eagle Ford. But you've obviously been drilling [indiscernible], it's [ $4.3 million ] in the press release.

Is that, I mean, is that all kind of cost inflation that you guys are baking in and presumably the CapEx guide is off the $5-and-change cost.

Yes, let me address it. So what we try to do in our remarks is just cover what's changed in our drilling and completion efficiency, without getting into pads and how you split wells, wells up over pads.

So if you look at our last wells that we drilled at Fasken, all-in cost would be about $5 million versus what we show in our comp -- presentation of $5.4 million target. So we're actually beating our target D&C.

We did allow for a little cost inflation in all of our D&C costs. But I can tell you at Fasken, we're beating that all-in.

Going back to drill in Artesia, where, if I remember right, there hasn't been a well drilled there in about 5 years. So can you talk about the decision to spend capital there and what you see, what you expect.

There's not a -- I didn't see a type curve for what you're thinking for Artesia. Can you just walk through why you decided to go back there and expectations?

Dustin, this is Sean, I appreciate the question. You're correct in that we have not been drilling in Artesia for several years.

But what we feel is, there's been opportunities to go in there and improve our results from historical well performance through enhanced completions, and also enhance our liquid portion in our production, so trying to access the returns of drilling in a more liquids-rich area. I will tell you, I think, that in our presentation that's on our website, we have posted a type curve for Artesia.

It's Slide 38 of the presentation. So what we have there is what we feel like we can do in that area based upon enhanced completion design that we're going to incorporate when we drill those wells.

Got it. And of the Artesia, kind of the breakdown there.

Is this representative for the whole section? Or does it [ grow off ] kind of an oilier piece and a gassier piece.

I think the -- so I apologize, the type curve, I do see the type curve now, but the 23% oil, 32% NGL mix that's in here, is that representative of the whole acreage position, or is there -- does it change across the acreage?

This is Bob. You're correct, it does change.

This area is kind of the northern piece of Artesia, that's where we will be concentrating this drilling. As you do move south, it does get more condensate-oriented.

And so the mix changes and the wells change, but we're focused on an area where we have good well control and it's representative of the more oily portion of the acreage position.

Okay, that makes sense. As you're looking at other opportunities, bolt-on opportunities or otherwise, how do you think about financing them?

Gerald

It's Gleeson Van Riet. I think financing strategy is pretty integral to any [indiscernible] we look at.

So from where we stand, we right now have got this RBL with a bunch of banks that are very supportive, which is great; that sets us up well. We're now relisted on NYSE, which again helps us well.

We're also out talking to a lot of other providers of debt equity, everything else in between, to make sure we've kind of got the full arsenal at our disposal. But also at the end of the day, and this could come down to what the situation -- the [ PD, how heavy ] is more acreage, what's the size, where are we in our development.

So I think from our standpoint, any financing we have will be kind of custom fit for what we do. We think we can take a pretty big bite of something we want to.

We're going to be very disciplined and selective as Sean said upfront about either [indiscernible] have to make sense, it's got to work with our footprint, it's got to work with our capability. So we feel in the Eagle Ford, we've got a very lean team and we can certainly run more than 1 rig.

But the financing will be customed, depending on the opportunity, and the opportunity is going to have to meet all our criteria for being strategic, and frankly, deliver good returns to our shareholders.

I was just kind of curious a little bit more on the M&A side of things and maybe just a little bit more generally what the leasing strategy is and what areas you're looking at, and maybe the size of potential acquisitions.

Chris, this is Sean. So I'll take that question.

As we think about growing our inventory and we're very focused around that, there's really a 2-pronged strategy that we're employing. The first is a leasing strategy that, primarily in the gas fairway, we feel like we have a competitive advantage in the gas fairway in light of what we've been doing there over the last several years that we have significant 3D seismic coverage.

We feel like we are optimizing our completion designs. So that's where we're really going to focus our leasing efforts.

Right now, it's around bolting on to our existing positions across that whole fairway from Fasken up to Oro Grande through our Uno Mas area, twofold opportunities that they're bolting on. We're finding that we're going to be able to extend laterals, which, that acreage creates a tremendous return.

But then, we're also putting together some newer blocks that [ are ] outright growth in our inventory. So that's kind of the plan around the leasing strategy.

As we think about the other growth pathway for our inventory on the liquid side, the leasing opportunities probably aren't quite as available. So we'll have to do that by looking at A&D activity, and like Gleeson mentioned, we'll be very diligent in how we go about doing that.

At the end of the day, we want to make sure that the full cycle returns all cost, including drilling and completion and the cost to add locations, and that makes sense to us. So that's really the approach we're taking.

It's a 2-pronged approach, leasing in the gas fairway, and then in terms of liquids fairway, we'll probably look more than the BD market.

Okay. Thank you, Amber.

Thank you, everyone for joining our first quarter 2017 conference call. See you next quarter.