Gulfport Energy Corporation (GPOR) Q4 2014 Earnings Report, Transcript and Summary

Jessica R. Wills - Associate Director of Investor Relations Michael G. Moore - Chief Executive Officer, President and Director Aaron M. Gaydosik - Chief Financial Officer Ty Peck - Managing Director of Midstream Operations J. Ross Kirtley - Chief Operating Officer Keri Crowell -

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Neal Dingmann - SunTrust Robinson Humphrey, Inc., Research Division Timothy Rezvan - Sterne Agee & Leach Inc., Research Division David Deckelbaum - KeyBanc Capital Markets Inc., Research Division Jason A. Wangler - Wunderlich Securities Inc., Research Division Ipsit Mohanty - GMP Securities L.P., Research Division Marshall H. Carver - Heikkinen Energy Advisors, LLC Leo P. Mariani - RBC Capital Markets, LLC, Research Division Subash Chandra - Guggenheim Securities, LLC, Research Division Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division Jeffrey Grampp - Northland Capital Markets, Research Division

Good day, ladies and gentlemen, and welcome to the Gulfport Energy Corporation's Q4 2014 Earnings Conference Call. [Operator Instructions] As a reminder, this conference is being recorded. I would now like to turn the call over to your host for today, Jessica Wills. Ma'am, you have the floor.

Thank you, Andrew, and good morning. Welcome to Gulfport Energy Corporation's Fourth Quarter 2014 Earnings Conference Call. I am Jessica Wills. With me today are Mike Moore, Chief Executive Officer and President; Ross Kirtley, Chief Operating Officer; Aaron Gaydosik, Chief Financial Officer, Keri Crowell, Vice President and Controller; Paul Heerwagen, Vice President of Corporate Development; and Ty Peck, Managing Director of Midstream Operations. I would like to remind everybody that during this conference call, the participants may make certain forward-looking statements relating to the company's financial condition, results of operations, plans, objectives, future performance and business. We caution you that the actual results could differ materially from those that are indicated in these forward-looking statements due to a variety of factors. Information concerning these factors can be found in the company's filings with the SEC. In addition, we may make reference to other non-GAAP measures. If this occurs, the appropriate reconciliations to the GAAP measures will be posted on our website. Yesterday afternoon, Gulfport reported fourth quarter 2014 net income of $110.1 million or $1.28 per diluted share. These results contain several noncash items, including a gain of $98.1 million due to hedge ineffectiveness; a gain of $84.5 million in connection with Gulfport's contribution of certain equity investments to Mammoth Energy Partners; a loss of $9.6 million pertaining to the mark-to-market of Gulfport's equity interest in Diamondback; and the loss of $12.1 million associated with the impairment of our Thailand asset. Comparable to analyst estimates, adjusted net income for the fourth quarter, which excludes all of the previous mentioned noncash items, was $10.7 million or $0.12 per diluted share. Gulfport's E&P capital expenditures and leasehold acquisitions for our 2014 program totaled approximately $1.16 billion. Alongside fourth quarter earnings, Gulfport had switched accounting reporting standards and will be reporting on a GAAP equivalent going forward. As reported, fourth quarter 2014 production averaged 382 million cubic feet per day, with the company exiting the year producing approximately 408 million cubic feet per day, compared to our previously announced exit rate guidance of 330 million cubic feet per day. Lastly, an updated Gulfport presentation was posted yesterday evening to our website in conjunction with our earnings announcement. Please review at your leisure. At this time, I would like to turn the call over to Mike Moore.

Thanks, Jessica. Welcome, everyone, and thank you for listening in. As Jessica detailed, yesterday afternoon we released our fourth quarter and full year 2014 earnings as well as announcing our 2015 capital budget. What we'd really like to accomplish this morning is to spend the bulk of the time on the 2015 capital budget, and then turn to your questions as quickly as possible. However, before I do that, I'd like to share with you just a few thoughts on our full year 2014 results. I'm surrounded by an exceptional team here at Gulfport, and this is my opportunity to recognize the hard work they put in during 2014. As you know, 2014 represented a transformational year for Gulfport and a coming of age for our development at the Utica Shale. During 2014, our team grew production by an industry-leading 255% driving a 93% increase in adjusted EBITDA and a 305% overall increase in proved reserves. This growth is a testament to the quality of our resource base in the Utica Shale, a basin that I believe generates some of the lowest cost and highest margin molecules of natural gas in North America. Building upon this momentum, throughout the year our team has implemented a number of operational initiatives, not the least of which is our managed pressure program targeted to further enhance returns by improving estimated ultimate recoveries, predictably of production, operational run time and overall capital efficiencies. In the meantime, we had [indiscernible] levels of activity in the Utica, drilling 85 gross wells and turning 63 gross wells to sales during 2014. Substantially, all of these volumes utilized our firm commitments to reach premium end markets in the Midwest, differentiating our molecules from those of molecules sold in the basin in the Northeast. By any measure, I am proud to say that 2014 was an astounding year. Now given the current commodity price environment, before I address our 2015 plans in detail, I would like to provide an overview on how we view our business in light of today's macro reality. In early August, when we first began our budgeting cycle for 2015, the CLF15 strip for WTI was trading near $93 per barrel, and NYMEX gas was hovering at $4 per MMBtu. At that time, Gulfport was operating 8 rigs in the Utica Shale. Following the OPEC announcement in late November and a milder-than-expected winter, today the CLF15 strip for WTI sits 38% lower at $57.50 per barrel and CLF15 NYMEX gas is trading 25% lower at $3 per MMBtu. Today, we operate half the number of rigs in Utica Shale we had running 4 months ago. While there has undoubtedly been a marked decline in commodity prices, we believe Gulfport's track record and continued dedication to capital discipline, conservative leverage and long-term value will be rewarded by this market that has undergone a fundamental shift in how to valuate investment in the E&P space. So now let's talk about Gulfport's goals for 2015. First, we are positioning the business to weather this downturn while also taking advantage of the long-term value proposition associated with exiting this cycle with strength. We remain firm in our commitment to make sound return-based decisions. The Utica is an exceptional rock, and when coupled with a strong capital structure, a well thought-out marketing plan and a strategic hedging program, we can generate a very attractive return on capital, while also growing towards a brighter macro environment for natural gas. Second, we are devoted to preserving industry-leading balance sheet metrics and maintaining a robust hedging program. We have a strong liquidity position to fund our anticipated 2015 activities, with $431 million of pro forma availability under our recently increased borrowing base, which we expect to continue to grow during 2015 and approximately $142 million in cash on the balance sheet. To bolster this liquidity, as our production base grows, we continue to be active in the hedging market to provide certanties in our realizations and cash flows. Based upon the midpoint of the guidance, Gulfport currently has approximately 60% of our 2015 Utica natural gas production swap at 403 per Mcf, locking in attractive returns for 2015. In Southern Louisiana, we have 1,000 barrels of our oil production hedged to $62.25 per barrel, which effectively funds our maintenance capital program for 2015. As we firmly believe a strong balance sheet works hand-in-hand with a well-executed hedging program, throughout 2015 we plan to continue to layer on additional commodity hedges and base the swaps as the opportunities present themselves. Today, our net debt to annualized fourth quarter 2014 adjusted EBITDA sits at 1.6x and based on our projected operating cash flows at current commodity prices, we estimate our net debt trailing 12-month EBITDA ratio will remain under 2.5x through year end 2015. Third, in balancing the compelling phase for investing in Utica, while also keeping in mind the importance of preserving our strong balance sheet, we intend to fund our 2015 activities from within cash flow and known sources of liquidity. To achieve this, capital will be allocated predominantly to drilling and completion activity in the wet and dry gas windows of Utica Shale, while limiting leasehold acquisition, nonoperated activity and noncore asset spending. The goal is simple: deliver high returns in today's commodity price environment, exiting the year strong fourth quarter 2015 over fourth quarter 2014, while protecting balance sheet strength and preserving financial flexibility. So with these goals in mind, let's move on to the specifics of our 2015 guidance. Gulfport announced yesterday evening that our Board of Directors has approved a capital budget for 2015 of $630 million to $690 million, a decrease of approximately 40% from our 2014 budget. This budget includes approximately $545 million to $595 million in exploration and production activities, with 96% of that allocated to the Utica Shale and the remaining 4% allocated to Southern Louisiana. Our leasehold expenditures budgeted for 2015 total $85 million to $95 million, which represents a 78% lower leasehold spend than in 2014. Gulfport has significantly dialed back spend for leasehold, as we plan to limit our expenditures to only acreage renewals and small acreage additions to block up planned units in our long-term development plan. In 2015, we have carefully considered every dollar being spent. And outside of our joint development area with Rice, we have considerably limited the amount of capital allocated towards nonoperated activity during the year. In 2015, we anticipate spending $125 million to $140 million on nonoperated activities in the Utica Shale, of which 75% is allocated towards our joint development AMI with Rice. To provide additional clarity on 2015 plans, we have broken out our Utica Shale well activity into 2 phases; drill and turn-to-sales. This year, we expect to drill 46 to 52 gross wells, equating to 28 to 32 net wells and turn-to-sales 49 to 53 gross wells, which equates to 42 to 46 net wells on our operated acreage in the Utica. In addition, we currently forecast our partners to drill the equivalent of 4 to 6 net wells and turn-to-sales 7 to 9 net wells on our nonoperated acreage during 2015. We enter 2015 with maximum flexibility related to rig contracts. As we stated on our prior call, of the 6 rigs we had running on January 1, 4 came up for contract renewal during the first quarter and the remaining 2 will come up for renewal by mid-summer. This exploration schedule has provided optionality as we plan for 2015 and left the team with the opportunity to negotiate lower day rates with contractors and optimize equipment packages to address the extraordinary pressures we are encountering in the southern portion of the play. When compared to fourth quarter 2014, the rig count in the Utica today has decreased only 9%, as compared to the total U.S. land rig count, which is down 30% and continues to decline week over week. I believe this serves as a testament to the value of the Utica and its ability to generate strong returns at today's pricing. That said, with commodity prices down significantly, late last year Gulfport began aggressively working with our vendors to negotiate service cost savings. Our purchasing department walked line by line through our AFB and to date we have received firm bids from vendors that represent an overall 10% reduction in service cost. Coupled with this, throughout 2014 Gulfport's continued focus on operational efficiencies have resulted in a 5% overall decrease to well cost. Between reduced service cost and efficiency gains, we are now currently estimating future well cost to be 15% lower than our estimates provided last November. Despite having firm bids in hand, for purposes of timing and conservatism, our 2015 capital guidance assumes service cost reductions are not realized until beginning the second quarter of 2015 and beyond. In the Utica, we currently have 4 operated rigs running in the play and plan to release 1 rig at the end of the contract next month. This will adjust to an average of 3 point gross operator rigs running in our acreage in the Utica during 2015. In our presentation uploaded to the website yesterday evening in conjunction with the earnings, we have provided a map that highlights the 2015 drilled and planned units, and as you can see, all 2015 drilling activities will take place in the wet gas and dry gas space windows of the play. In addition, we currently estimate that the nonoperated activity occurring on our acreage during 2015 equates to 1/3 of a net rig running through the year in the dry gas window, bringing Gulfport's total operated and nonoperated to an average of 4 rigs running in 2015. To better align with our planned operated rig count during 2015, we have started to slow our pace of completions. During 2014, our operations team saw a tangible benefit with the creation of a well inventory with the goal of maintaining 3 to 5 pads in the inventory at all times. Although our 2015 plans forecast a reduced level of drilling activity, the goal is to maintain a similar well completion inventory and we currently forecast to exit 2015 with approximately 23 to 29 gross wells in inventory. In addition, by slowing the pace of completions, we are being strategic with our turn-in schedule throughout the year, maximizing the value of our molecules while slowing cash outflows. At this level of capital spend, Gulfport anticipates production to be 432 million to 480 million cubic feet per day, an increase of 79% to 100% over 2014. We let our balance sheet strength and liquidity drive the activity pace for 2015 and due to the quality of our assets and the strong performance of our wells, we will see substantial growth this year. We have some of the highest realizations and the lowest cost base in America and when you back up this with the strength of our balance sheet, we are more than comfortable with this level of activity. In addition, this year's program will put Gulfport at a good spot to deliver strong results for many years to come. In terms of production mix, our transition is complete and we currently expect full year 2015 production to be approximately 75% to 85% natural gas. During the first quarter of 2015, Gulfport expects production to average 378 million cubic feet to 384 million cubic feet equivalent per day. As always, first quarter production has been seasonally lower as a result of cold winter weather. We are committed to maintaining strong realizations during 2015 and to provide security and foresight to revenue. Gulfport was an early mover in securing firm commitments that offer deliverability of our products at attractive price [indiscernible] at relatively low fixed cost. Based on the mid part of our guidance, we currently estimate 90% of our 2015 production will be covered by firm agreements. Based on our current firm portfolio and our expected 2015 production, before the effect of hedges the company expects basis differentials to range $0.52 to $0.58 off NYMEX for natural gas, approximately 45% to 50% of WTI for natural gas liquids and approximately $10 off WTI for oil. As a reminder, Gulfport's firm transportation expense is accounted for in our reported realized price. In terms of cash costs, as we bring on more gas [indiscernible] production, we continue to see unit costs trend down, and you may find detailed information pertaining to each line item available in yesterday evening's press release. Before we move to Q&A, I would like to take a moment to commend our leadership team and the Gulfport staff on their execution of last year's plan and their ability to deliver exceptional results in all aspects of our operations. I'm confident that the team we have in place today will continue to excel going forward, regardless of the challenges we face, as a result of the current commodity backdrop. We have a solid asset base with a large presence in one of the lowest cost gas bases in North America and a strong balance sheet that allows us to execute and be opportunistic as the macro picture evolves. I believe Gulfport remains an attractive opportunity, as we are poised to provide strong returns and financial stability during 2015 and beyond. There are not many companies in the E&P space that can say the same. This concludes our prepared remarks. Thank you, again, for joining us for our call today. And we look forward to answering your questions.

Andrew, please open the phone line for questions from the participants.

[Operator Instructions] Our first question is from the line of Ron Mills from Johnson Rice & Company. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: When you talked about the 23 to 29 wells in inventory at the end of '15, how does that compare with the end of '14? And when we look at the number of wells you plan on turning to sales, I know you had targeted 14 to 20 per quarter in '14. Is it -- are you expected to complete a similar amount each quarter? Or how is that to be weighted through the year?

Well, to give you some sense of comparison, Ron, we had 25 wells in inventory at year end 2014, and that compares to our guidance at year end 2015. As far as the turn-in schedule for 2015, Ron, I think the way to look at it it's going to be a very linear ramp. And so as you're looking at modeling, just think about -- it's very, very linear this year. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And then when you talk about the 15% cost savings that you expect to achieve, I guess beginning in the second quarter, for your typical 8000-foot lateral, does that get you down to the $9.5 million to $10 million range? And if so, given your relatively strong pricing, where does that put you in terms of the return paradigm for your wells, given the type curves you provide in your updated presentation?

Well, you're right on the cost. I think the exact calculation at 8000-foot lateral is $9.2 million for the condensate, $9.8 million in the dry and the wet gas windows. And so that represents about a 15% reduction over what we talked about in November of last year. The way we're looking at returns right now, of course we haven't put out a type curve on the dry gas window yet, but certainly wet gas has 50-plus-percent returns at this point. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And then in terms of the optimized wells that are in on Slide 14, you now have another 2 to 3 months of data. Any commentary on the optimized curve coming in at or a little bit below the 3.1 million BOEs? Is that data bias in terms of which wells are -- which wells were completed when?

Well, I'm glad you asked that question, Ron. First of all, let me say that we continue to be very pleased with the performance of the wells under the managed pressure program. And you might recall that we put the condensate window of the play on the managed pressure program earlier than we did the wet gas. We just started in the wet gas window in, I believe, April of last year. But the truth is, although we have a larger dataset of wells in the wet gas window now, a lot of those wells didn't come on till the back half of 2014. And so we believe that as those wells continue to produce for a longer period of time, you will see that curve trending up. And we're -- everything we're seeing right now in both windows, the wet gas window and the condensate window, we believe is very positive. We think in the wet gas window we just need a little more time. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: So how many wells are in that curve and how many are with the managed pressure versus not? Because if it follows a similar trend as what happened last year with the condensate, then obviously that would be a pretty big positive?

Ron, I don't have the exact number in front of me. I can get that to you.

Our next question is from the line of Neal Dingmann from SunTrust.

Say Mike, first question. Just wondering, how do you think about balancing the future production growth with your financial flexibility that you all have? You obviously have a better balance sheet than most others out there. And then wondering if you could talk about the potential outspend you see around the end of the year, given this?

Neal, it's Aaron. Really we think it speaks to the quality of the rock and the quality of the people that we can achieve 80% to 100% year-over-year production growth, while also reducing our total CapEx by about 40% year-over-year. And we're going to be able to do this, as Mike mentioned, by exiting the year at under 2.5x leverage. So as we look into 2016 and kind of exiting 2015, just with the reduced spend kind of getting the full benefit of the service cost reductions and the efficiencies and then also having to improve production and EBITDA as we exit the year, we still think that, that 2.5x number is something that we can maintain even after 2015. So we feel pretty good about the flexibility that we have as we exit 2015 and on a go-forward basis.

And then second question for -- maybe for Ty. I was wondering, could you walk through a little bit, Ty -- I was just looking at the slides on the FT contracts. I think it's -- and I forget, around where you basically showed not just for '15 but what's coming on in '16. If you could walk a little bit on what you have coming on and kind of how you see that or what that means for realized prices. I guess what I'm suggesting as far as what sort of is that, more as a fixed cost versus a percentage of NYMEX as that comes on?

Yes. Thanks, Neal. I'd say to that last point there, I think last year we saw where our fixed -- transportation is more of a fixed component and therefore, when price of the commodity started coming down, the percentage was coming down stronger than we expected. Going forward, that's why we're trying to go more with the fixed guidance. This year, '15, we're going to have Tennessee capacity come on in April, which is a big percentage of our portfolio. Rex, we're still hopefully going to see that come on in June. And so we're going to see more sales to the Gulf this year. And then, middle of the year, when Rex comes on, we'll continue to see exposure to the Midwest even though the production continues to increase. And then, finally, I'd say that we are actively monitoring the release market for the second half of the year and just making sure we're optimizing our portfolio.

Got it. And then, just last question likely for Mike. Mike, just wondering, how do you guys look at M&A? I'm just wondering, I guess, more particularly, would you guys be interested here in increasing your current working interest in existing acreage? And then, again, if you were approached by potentially a large private with acreage close to yours, would you be interested in a package like that?

It's a good question, Neal. There's certainly been a lot of talk in the industry about potential M&A activity. First of all, let me say that we are very focused on developing the Utica acreage that we have. I think we have an exciting 2015 laid out. I think we have a good plan for '16 and beyond. Obviously, in times like these, and I've been through many of these cycles in my 37-year career in the industry, there are going to be M&A activities. I'm not going to speculate at this time on what those opportunities might be. But of course, we always want to create additional value for our shareholders. We'll evaluate those opportunities when and if they come in. But just to dodge your question, we are very focused on developing the Utica assets we have.

Our next question is from the line of Tim Rezvan from Sterne Agee. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: I was hoping first to piggyback on the prior question. I guess, what are you all looking at for kind of firm commitments out in 2017 and beyond? I see that your commitments sort of plateau in that period.

This is Ty again. As far as when we look out there right now, the basin is starting to strengthen when you get beyond '17. That being said, there's really -- the projects that are coming on that are committed to today are actually coming on late '17 into '18. So those are 20-year commitments often times. So we're really taking a diligent approach to that and making sure we pick up what we need. And if a project's justifying that with our long-term outlook, we will participate. So that's kind of why it plateaus right now into '17 or past '17. Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Can you talk in general terms about what the terms are on these new projects being proposed?

They're pretty much out there. I don't know if I will get into specifics. But there are projects out there, back to the Gulf, back to the Southeast, Newlands [ph] to the Midwest. They're all over. So... Timothy Rezvan - Sterne Agee & Leach Inc., Research Division: Okay, okay. Fair enough. And then one last one. I was wondering if you could quickly give any more color on the first 4-well dry gas pad. It's performing in line with expectations, was the comment in the release. Your JV operator has been probably the most granular on the dry gas part of the play. What can you say right now? Because it seems like you've had over 2 months production from these wells.

My comment would be, Tim, that those wells are performing as expected. So the pressures are good. Actually, a little better than expected pressure drawdown, flat production. So we're very pleased with what we're seeing right now.

Our next question comes from the line of David Deckelbaum from KeyBanc.

Trace, if you could provide some color on just the way that you're completing the dry gas wells. Do they mirror that of your nonoperated partner in Belmont? Have you all agreed on sort of the right well design there for the rest of the year?

David, this is Ross Kirtley. We watch what our partners do. And we certainly pay attention to the amount of sand per foot and the injection rates and those types of things. We look at that. But we also have our own recipe that we try to follow. We haven't deviated too far from that. But as we move further and deeper into that play, certainly we'll collaborate with our partners and see if we can optimize the completion techniques there.

So I would say Rice, I believe, is a little more aggressive on the sand loading. But we have trended down on stage spacing this year. We talked about that previously. So we're still showing very good results. But we continue to tweak our design as we go, and I think that will be an ongoing process for all operators out here for years, probably, actually.

And the cost per lateral foot on the dry gas wells is pretty much in line with what you guys have for the wet gas at $1,100 and change?

That's correct.

Okay. And then the last one I have is just for Aaron or Michael, or whoever wants to take it. How do you guys think about the potential for being over-firmed as you get through, kind of, like the end of '15? And is there a fair portion of your portfolio that you can kind of just market inexpensively?

This is Ty. I would say that, yes, there is always room for optimization. I'd think we're really in a good balance between producing into our firm. I don't see that to be out of balance. And so, but there's always -- that being said, we'll always try and optimize to make sure that we're always in sync there.

David, this is Aaron. I'd add that a good firm portfolio has value in and of itself. So we're happy with what we have and having that good balance between flexibility, but base volumes out of the basin, I think Ty has done a great job and his team of getting that locked up.

Absolutely. I'm just trying to get a sense of if you guys -- how you guys think about the potential liability for perhaps having a little bit too much capacity, depending on what your schedule is going to be and if there's sort of like a cheaper transport option that you have that you could give up that really isn't going to show very much in the cash flows.

Yes. So we've got -- we're in a long-term development program, so we're aware of that. But we also understand the commitments that these incremental projects have for longer term and that's what we're trying to balance, kind of meeting the more near-term several years out availability and kind of understanding what those options are rather than only looking at longer 15, 20-year opportunities. So we're -- David, that's definitely on our radar screen, and that's definitely part of the decision-making process we have as we analyze the opportunities to pick up additional capacities out of the basin.

And just to add, not probably really say anything different then Ty, and Aaron said that as we all move forward in this play, we have to be very thoughtful and strategic about what you do from a firm perspective. It's -- obviously it's a great way to minimize your risk of in-basin pricing. But on the other hand, to your point, these are long-term commitments. And then, moving forward, these projects get more expensive. And so you want to find the right balance. You don't want too much; you want just enough. And so we've worked really hard to try to find the right balance, and we'll continue to do that going forward.

Our next question is from the line of Jason Wangler from Wunderlich Securities.

Just kind of another question on something you guys have hit on in the past, just where you stand with the HBP status of the acreage up in the Utica and kind of how that's shifting as you move around from the rig count perspective?

I think at this point, Jason, we are about 30%, 35% held at this point with the joint activities that we've had.

Okay. And then, just kind of more just a housekeeping, I suppose. On the guidance and things, from the cost perspective, is it going to be like last year? Obviously, as you ramp up you're going to kind of see those trend down, kind of quarter-over-quarter as we get throughout the year.

Well, I think that's true for LOE. But I think the others won't be as linear. But yes, certainly, as we ramp volumes, especially in the dry gas window, you're going to see generally unit costs coming down. Again, just keep in mind, it's a very linear build this year and not quite as lumpy as we've had in years past.

Our next question comes from the line of Ipsit Mohanty from GMP.

I look at Slide 12, I believe, on your presentation release and can't help but notice that you're going to drill about 12 wells on the wet gas but complete just a few of them. So going into '16, is it fair to assume that your backlog of wet gas wells kind of indicate you'll probably have a better liquid mix in '16 versus '15?

I think that's a true comment. So, yes.

Okay. And then on the same lines, would it be fair to assume, then, looking at 12 wells being spud this year in the wet gas, you're probably going to let one rig run through for the whole year, and then the rest 2 can split between your AMI and non-AMI in the dry gas?

I think that's right. I did want to remind you, though, when you think about wet gas this year, you've got to think about the fact that we're drilling on the east side of the window -- of the wet gas window. So those wells are going to be pretty lean. They'll be -- they'll tend to be more gassy than they will be liquid. So just keep that in mind.

Sure thing. And then my final. What does it take for you to put any kind of activity back on the condensate window? Because you're clearly getting rid of your completions as well this year -- past sort of getting through that. So just curious, what levels of oil price would you put a rig back there?

I think there would have to be a meaningful improvement in oil. The returns that we're getting in the wet gas window and dry gas window, quite frankly, are really good. And we're going to -- you've got to keep in mind, we don't have a lot of acreage in the condensate window. The majority of our acreage is in the wet gas window and the dry gas window. Those have the better returns. So if we see an improvement in price -- and I can't tell you what that price will be at this point in time because there's still a lot of moving factors out there. There are cost reductions possibly ahead that we haven't realized yet. So we're going to be focused this year on the wet gas and dry gas window, and I doubt that you'll see us reallocate a rig.

And Ipsit, it's Aaron. I think one thing I'd add to Mike's comments is that whether you're talking about oil or natural gas, we don't only want to see a temporary uptick in prices, but we want to see it sustain. So that's kind of part of the checklist that we have to have met before we think about moving things around or changing activity levels.

Then would it make sense for you to probably give that off to someone who can then consolidate it or who can bolt-on rather than for you guys to keep that portion of the acreage in that window?

I don't think we're ready to let go of our condensate acreage. 6 months ago, you heard us talk about potentially ramping up out there as well costs have come down dramatically, particularly for that window. So that being said, you may or may not know this, but there's a lot of trading going on out here between all the operators as they continue to block up their acreage. And so while there may be some trade opportunities, I don't think strategically we're ready to try to monetize our condensate position. We still believe it's good acreage. We like the liquid aspect of it.

Our next question is from the line of Marshall Carver from Heikkinen Energy.

You talked about maintaining 23 to 29 wells in inventory. But you're putting approximately 14 more wells for sales than you're drilling this year. Is that 23 to 29 wells in inventory a current inventory count or not a year-end inventory count?

Marshall, it's Aaron. Let me clarify a few things. We exited 2014 with about 25 wells in inventory, and that's gross. And then on Slide 12, the numbers you're looking at that -- kind of that 14-ish delta. Just keep in mind that's a net. So there's the working interest kind of playing in there. But if you kind of step back and look at just gross activity, the way to think about it is, for 2015 we expect to drill 46 to 52 gross operated Utica wells and we're going to turn in line about 49 to 53. So that's how we're able to keep that 23 to 29 wells in inventory as we exit 2015.

Got you. Okay. So gross versus net difference. And when are you all expecting to provide a dry gas type curve?

Generally our guys like to see at least 6 months of production before they want to put out a type curve. So maybe sometime this summer.

And one final housekeeping question. As far as the G&A guidance goes, is that all cash? Or is there a percentage of stock compensation in that? And what would that be?

This is Keri. There is a portion of a noncash stock comp in that as well. But -- we can give you that number offline if you'd like it later.

Our next question is from the line of Leo Mariani from RBC.

Obviously a pretty big jump -- I'm sorry, drop in capital spending here during 2015. Clearly commodity prices have come down significantly, which you articulated here. What type of gas prices will we need to see for you guys to want to get more aggressive? Do we need to get back to $4 before the rigs start coming back? Trying to get a sense of that.

Well, it's a good question, Leo. And I don't know that there's a definitive answer. It's similar to the answer I gave on the oil window. It's more than just commodity prices. It's -- we want to -- again, we want to live within our liquidity, maintain a strong balance sheet. We're not sure if we've seen all we're going to see yet on service costs. So if service costs continue to come down that could cause us to rethink things. I'd say if we saw natural gas prices move up 50% in the back half of the year, we might rethink our rig count. But we need to see some sustained recovery in prices, $0.50, I don't know what I said, but $0.50 in the back half of the year. But we need to see some sustained movement in prices and some clarity on service costs before we commit to adding a long-term rig -- a long-term contract rig.

Okay, that's helpful color. And I guess, can you talk longer term about managing the acreage? Obviously the big cut in CapEx this year. But you need to ramp back up in '16 and '17 to hold a lot of your acreage. And I'm assuming you guys also have the options of extension payments. Can you just kind of talk a little bit of that dynamic?

Yes. So it's a good question. We do have 5-year leases with 5-year options. So I think, as we were planning for 2015 and beyond, we are not one of those plays that has a gun to our head, we have to get all of our acres drilled up right away. We're certainly willing to pay the lease bonuses again if we need to. In fact, we'll do a few renewals that are due. At the very end of this year will be our first renewals. So we've got plenty of time to drill and there may be some money in our budgets going forward for renewal payments. But I think it would be minimal.

Okay. That's helpful. And I guess any comment on some of the rest of the assets in the portfolio x the Utica. And if you guys have made any sort of decisions as to what to do with some of those?

No firm decisions yet. We've been pretty vocal about the fact that we are running a process in Niobrara. We continue to own Niobrara. It's not a large investment for us. We are not putting money into it. Southern Louisiana, you've seen that we pulled back our CapEx budget. And then Canada, we will wait until the markets are right and hopefully execute some kind of a capital event there. So you saw us write off one of our Tatex Thailand assets this year. We're certainly -- we're allocating 90% -- 96% of our capital to Utica this year. So we're very focused on Utica development.

Our next question comes from the line of Subash Chandra from Guggenheim.

So last year was a big change in improvement and how you completed these wells. And I was curious about the current year, what's on the to-do list. I think you referred earlier that you're happy with the recipe you have in the various phases, but if you were to tweak it, what areas you would tweak it in?

Subash, this is Ross. I think what you're going to see is have smaller stage spacing. We're going to be in the same range of sand placement as we have been, probably in the 1,500 to 1,800 feet or pounds per foot. So I don't think you'll see a lot. The major change is going to be in the stage spacing, shorter stage spacing.

How about like staying in zone or types of completion recipes?

Well, obviously, the goal is to [indiscernible] zone. I don't know that we'll change our recipe much other than we will, as I said earlier, we will work with our peers, Rice and -- we have a collaborative effort with them and we will learn from them, as they do from us. And we will adjust our recipe accordingly.

Yes. And on that point, I guess on the collaboration, I mean, where do you think the conversions might be? In your comments earlier, seemed like you were happy with what you just said about sand per feet as well as pump rate, et cetera. But where might you converge to what Rice is doing?

Well, every operator out here is going to have its own thought process, both geologically and operationally. And Rice has done some really good things. And we are -- we have a very good partnership with Rice. We're sharing information back and forth. We learn from them; they learn from us. And Ross mentioned we are moving to shorter stage spacing. We use different amounts of sand than Rice does. So what's the convergence going to be between operators? I don't know, quite frankly. Eagle Ford, that convergence has been going on for 5 or 6 years. We're not there yet. Stage spacing we think is most important as it directly correlates to the amount of surface area that you expose yourself to, so that you have the most reservoir available to you. Ross' group has been working on, certainly, other smaller efficiencies as well. But what the convergence is between the operators I'm not sure. It's still a work in progress.

And then secondly, can you talk me through how you secure firm capacity? I guess it's a volume commitment coming from an acreage commitment. And I guess, really, what I'm asking from a big picture is that you sort of stabilized at 2.5x, and absent a significant gas rally or more severe cost inflation than what you've assumed, I suspect you'll probably be in that range for quite some time and if there is a need to accelerate beyond what that capacity is to secure new firm?

This is Ty. The new firm is something that we have to look at today to really participate in 2 years, 3 years from now. Just -- that's just the reality of the marketplace because the projects are no longer tweaking their systems. It's more green grass or green roots start-up type projects. So what we're really doing is trying to put sensitivities around, if prices change in the basin or if they don't, kind of take that approach and really look at it if there's a project that maybe helps diversify the portfolio and improves it yet doesn't put us at a significant risk. So there's really tension between kind of the outlooks and sensitivities around the different basins and pricing around each of those basins. It's not an easy process.

Yes. This might be a tacky question, but just today is a pretty heavy equity day, number of operators issuing equity. And just your thought process on issuing equity, just to remove that EBITDA constrain period. Not that you have to grow faster than you are, but in terms of, I think Ron asked a question on acquiring other stuff and consolidating more acreage, et cetera, et cetera, and possibly growing at a faster rate just to remove any sort of FT overhang over time. And I mean, I suppose in one way it would eliminate all those questions.

Well, of course, as CEO of a public company, I can never publicly say I'm not going to raise equity. But look, we're positioned to deliver up to 100% growth with the balance sheet that we have today and the sources of liquidity we have today. When we were planning for 2015, we wanted to live within those sources. If there are creative opportunities that come along, then we'll decide at that point what makes sense for our shareholders. But right now, we're focused on living within our balance sheet, sources of liquidity, and we also have to look at how 2015 affects 2016 and what appropriate growth levels are there. So again, we've been pretty conservative from a leverage perspective, but we are in a different part of the play now. We're in development mode of Utica. So sometimes different capital structures make sense in different phases of the play. But I think we've demonstrated today with our budget that we're very focused on living within our balance sheet liquidity at this point in time.

Subhash, it's Aaron. I would just add that right now we're fully funded. So that's why we feel good about the plan that we have, being able to deliver the growth for 2015 and then also being in a good position beyond that. So we're in a good spot, and we're going to make sure we stay that way.

Our next question comes from the line of Jeoffrey Lambujon from Tudor, Pickering, Holt. Jeoffrey Lambujon - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division: Just tacking onto the completions and the tweaks question, last quarter you mentioned the Darla pad being put on production. Can you remind us of what you're testing there and maybe give an update on where things stand?

Well, just briefly, we were testing, obviously, spacing opportunities from all the way down to 300-foot up to 1,200-foot apart. We were doing a lot more than just testing spacing. We were also trying to look at other things. So we're producing those wells now. Unfortunately, we don't have all the data analyzed that we've been getting. As we mentioned, we were getting over 3 terabyte of data a day, and it's just taking a while to sort through, analyze the data, correlate it and draw our conclusions. So it's going to be sometime later in the year before we're able to draw some conclusions. We're looking at cluster efficiency, stage spacing. We're looking at a lot of things in the Darla pad. So there's just a lot of science going on in this pad that we don't want to get ahead of ourselves in drawing conclusions. But keep in mind, we've done other down-spacing experiments on other pads earlier on. So we have some additional data from our wells, as well as our peers are also doing things. So again, this is another part of the play that at some point will converge probably, but it's an ongoing process at this point.

Our next question comes from the line of Jeff Grampp from Northland Capital.

Most of mine have been asked and answered. Just had one quick one. On the well cost reductions, you've obviously made some nice progress to date, but wondering how much more room you think there is left on both just general service reductions and then maybe internally through the improved efficiencies, how much more room there is to improve on the cost side of things?

Yes. it's a good question, Jeff. All we know is where we are at this point in time. We -- I think our well costs are lower than a lot, but we're not giving -- we're not talking about additional service cost reductions until we have them in hand. And so we've been very careful in our budget to only include service cost reductions that we actually have in hand at this time, plus our efficiencies. There may or may not be more coming. It may be producer by producer. We've been one of the most active operators up there. I think we were already able to negotiate good pricing. And so you may hear different operators talking about different things, but I will tell you that our folks have worked very hard, going line by line on the AFB, negotiating, and we feel good about where we are right now. And we'll just have to see if there's anything further coming.

That's all the time that we have for questions for today. So I'd like to turn the call back over to Mike Moore for closing comments.

Thank you, Andrew. We appreciate your time and interest today. And as you know, this is a busy time for many of you on the call. We enjoy working with each of you and feel privileged to be included in your coverage universe. Should you have any questions, please do not hesitate to reach out to our Investor Relations team. This concludes our call.

Ladies and gentlemen, thank you again for your participation in today's conference. This now concludes the program. And you may all disconnect your telephone lines. Everyone, have a great day.