W&T Offshore Inc (WTI) 2014 Q4 法說會逐字稿

Greetings and welcome to the W&T Offshore Inc fourth quarter of 2014 earnings conference call.

(Operator Instructions)

As a reminder, this conference is being reminded. It is now my pleasure to introduce your host, Lisa Elliott. Thank you, ma'am. You may begin.

Thank you, operator, and good morning, everyone. We appreciate you joining us for W&T Offshore's conference call to review results for the fourth quarter of 2014.

Before I turn the call over to the Company, I have a few items to point out. If you wish to listen to a replay of today's call, it will be available in a few hours via webcast by going to the Investor Relations section of the Company's website at www.wtoffshore.com or via a recorded replay until March 12. To use the replay feature call 201-612-7415 and dial the pass code 13599736.

Information recorded on this call speaks only as of today, March 5, 2015, and therefore time-sensitive information may no longer be accurate as of the date of any replay. Please refer to our fourth-quarter 2014 earnings release for disclosure on forward-looking statements. At this time, I'd like to turn the call over to Mr. Tracy Krohn, W&T's Chairman and CEO. Tracy?

Thank you, Lisa. Good morning, everyone. Thanks for attending our fourth-quarter 2014 earnings conference call. Joining me this morning is Jamie Vazquez, our President; Danny Gibbons, our Chief Financial Officer; Tom Murphy, our Chief Operations Officer; and Steve Schroeder, our Chief Technical Officer.

Yesterday afternoon, in a detailed news release, we announced our fourth-quarter results, our year-end 2014 reserves, and our 2015 capital plan and guidance. So as is our custom these days, we'll ask that you refer to that press release for the numbers and we'll primarily focus on prepared remarks on key operations and plans for 2015. That will allow time for your questions.

As you saw in the release, we had good operating results in the quarter, as production of oil, NGLs, and natural gas all came within our guidance. Operating expenses also came in as expected, except for LOE, which was a bit lower due to less workover activity than planned and the beginning of reduced costs. You'll note in our LOE guidance that we expect costs to continue moving downward.

We produced on average 50,000 barrels of oil equivalent per day in the fourth quarter of 2014, which was 7% above our third-quarter production. For the full year, we produced an average of about 48,300 barrel of oil equivalent per day, which was similar to last year.

We reported year-end 2014 proved reserves of approximately 120 million barrels of oil equivalent and we replaced 113% of our 2014 production. The components of our proved reserves are made up of 52% crude oil, 13% NGLs, and 35% natural gas. Much of our proved reserve additions in 2014 came from our drilling activity at our Yellow Rose field in the Permian Basin, and from our Dantzler field in the deepwater Gulf of Mexico.

I'd like to point out that although we booked some reserves for Dantzler in 2014, it was only a portion of what we expect to book once we move this field into production. So our current proved reserves don't reflect anywhere close to the additional contribution we expect to ultimately receive from Big Bend and Dantzler once we get these fields online in 2015 and 2016 respectively. We also added about 6 million barrels of oil equivalent from acquisitions which included interests acquired at Neptune, Ewing Banks 910, High Island 129, and Fairway fields.

Although our operating results came in as expected, our financial results were affected by lower realized oil and NGL prices, which were about 25% lower than last year. Our EBITDA was $100.3 million in the quarter and $573.2 million for the year. Our EBITDA margin was 60% for the year, down only slightly from 62% last year.

Of course, at current prices, our financial results are affected, and we're responding with a much-reduced capital plan in an aggressive effort to reduce costs and expenses. Having been through several of these cycles, we know the importance of making quick and decisive adjustments to our strategic plans and we're taking a conservative approach to our use of capital until economic conditions improve.

When commodity prices decline quickly, the cost of goods and services typically decline as well, but more slowly. The ability to be patient and demonstrate flexibility is really important under these conditions. We're the operator of most of our production; the majority of our lease acreage is held by production.

We have the ability to minimize our drilling budget, work with our service providers to reduce costs, and wait for commodity prices and margins to improve. When conditions are right, we have the flexibility to reinitiate a more robust drilling program. For now, we're focused on our highest impact projects and on wells in which much of the investment has already been made.

We established a 2015 budget of $200 million, of which $169 million is for deepwater projects, which are primarily already in progress. All of these are high-quality projects and we remain very enthusiastic about moving forward with them, even in current conditions. Development operations are on schedule to bring our deepwater discoveries at Big Bend and Dantzler on production as planned and we're making good progress through our ongoing projects at Medusa and Ewing Banks 910.

The remaining budget is allocated to the Gulf of Mexico shelf and Permian Basin operations. Those funds are dedicated to completing certain operations that were already underway or reaching a stopping point. We were working with our service providers on a daily basis to bring down costs, but we may choose to delay the completion operations on some of the Permian wells while we work to reduce completion costs to optimize our total completion economics, and obviously, most of the cost of the wells over there has to do with the completions and fracking of same.

Our borrowing base is $750 million and the current amount outstanding on the revolver is around $460 million, so liquidity is about $290 million. The spring redetermination is coming up in April; a new borrowing base will be set at the end of that month.

Our liquidity is strong and we want to make sure that it remains that way. That's why we've reduced our capital expenditure program and are suspending our dividend.

Cost of goods and services need to get much better aligned with the current commodity price environment before we deploy additional resources to new projects. We think that's the right thing to do for all of our shareholders. Cost of goods and services are already moving down pretty quickly, so margins should improve and move more in line with historical levels.

Although we've reduced our capital plan to less than one-third of our 2014 capital spending, we still expect production to be in line with or even to exceed our 2014 production levels. This is because of contributions from various projects and additions to our portfolio, including the Neptune field, which will contribute for the entire year; two new wells drilled in 2015 at Medusa, which will add significant volumes; and new production from our Ewing Banks 910 expansion project, which will begin to add volumes in the second half of 2015. Additionally, material rate contributions from Big Bend in late 2015 will add measurably to our exit rate this year, followed shortly thereafter by the two Dantzler wells scheduled to come online in late 2015 or early 2016.

Okay. Let me update you a bit more on the projects that we have in our 2015 plan. At Big Bend, we are on schedule to tie in to the nearby Thunder Hawk production platform. Both of the Dantzler wells have been completed now and are ready for the installation of new deepwater infrastructure, which will occur over the coming months.

Both of these wells will also be connected to the Thunder Hawk platform. Big Bend and Dantzler will together be referred to as the Rio Grande Loop, which, in aggregate, is expected to contribute 8,000 to 9,000 barrels of oil equivalent per day net to W&T's interest.

At Medusa, we're drilling two exploratory wells, targeting multiple stacked oil sands. As a reminder, it's a deepwater field, Mississippi Canyon 538 and 582, in which we acquired a 15% interest in late 2013. It did fit our acquisition criteria perfectly as a quality producing field with excellent upside potential.

The first well, the SS No. 6 reached total depth in January at 12,500 feet and accounted over 180 feet of net pay. The second well, the SS No. 7 is currently drilling.

We expect to perform completion operations on both wells in the second quarter and we should be able to commence production in mid-2015. We expect these exploratory wells to move previously unbooked reserves into the proved reserve category.

Platform rig is currently on location, drilling the A-5 Sidetrack well at Ewing Banks 910. First well in the program could initially include one to three wells in 2015.

The A-5 Sidetrack is expected to be completed and put online in the second quarter. The second well, the A-8, could be put on production in the third quarter.

We're highly enthusiastic about this project based on brand new seismic data and analysis that indicates it has similar characters to our Mahogany Field. We've identified several additional targets beyond the first two wells, and believe the resource potential at Ewing Bank 910 could be quite significant. We could opt to propose a third well this year with our joint interest operator. We'll keep you posted.

We suspended operations on the A-18 well at Mahogany and have opted to instead focus on analyzing new data we recently obtained over the field and watch the performance of the T-sand producing from our A-14 well. Since we've brought the well on in mid-2013, it's produced well over what we had initially booked as proved reserves, with steady bottom hole pressure and steady production rates. Current gross production is around [3,000] barrel of oils equivalent per day, so while we're waiting for the cost of goods and services to come down, it's a good time to focus on field analysis and identify additional upside opportunities.

At our Yellow Rose Field in the Permian Basis at the end of the year, we had 10 wells awaiting completions, 6 of which were horizontal wells. Our vertical program supported our strategy to hold the vast majority of our Yellow Rose acreage by production, which at year-end was 90% HBP.

Throughout the year we benefited from a large amount of data coming from the industry regarding optimum drilling and completion techniques and the productivity of various formations. Our 2014 drilling success and two new horizontal benches allowed the Company to move guidance from our prospective resources, or exploratory volumes, into proved reserves, as we achieved successful wells in both the Wolfcamp B formation and the Lower Spraberry Shale. Our reserves position in these two formations is expected to grow, as we have only booked a small number of wells based on our initial success.

We're pleased that our well results have continued to improve, with our most recent operated horizontal wells averaging peak rates of around 1,000 barrels of oil per day. The rates normalize for a 7,500 effective lateral length. We've also partnered with an adjacent operator to drill on our acreage, with excellent results. The most recent non-operated horizontal well test was the Lower Spraberry Shale in Andrews County and achieved a peak rate of 1,709 barrels of oil equivalent per day, that's 91% oil, or 224 barrels of oil equivalent per day per 1,000 feet of lateral.

While we have a high degree of confidence in the quality of our acreage, we plan to leverage the fact that many of our opportunities in this core area are discretionary, creating an opportunity for W&T to optimize value from the field. Through quality drilling and completion practices, some of our latest wells are performing in the upper tier of well performance within the entire basin, and allows us to be selective in the short-term, and at the same time, be positioned to accelerate drilling activity as our operating margins improve.

In the short term, we will preserve our capital and continue to closely watch industry activity and wait for margins to improve before reinitiating our program. We're very excited about the performance in our newest horizontal bench, and are equally excited about several other benches that we've not been able to test and derisk, but have been tested by others. Our objective is to add these new benches into our multi-year plan for the field, as we continue to develop and monetize each new formation and bench.

We believe that our deep position in the Midland Basin allows for higher thermal maturity and higher pressures, which increases the potential for recovery. To date, we've proven up three horizontal formations in our acreage position. As we test and add new horizontal formations, we will effectively multiply our drilling inventory considerably, and we think we're well positioned to realize substantial value for our shareholders.

With that, operator, we're ready to take questions.

(Operator Instructions)

Our first question comes from the line of Neal Dingmann with SunTrust. Please go ahead with your question.

Good morning, Tracy.

Good morning, Neal.

Three questions -- Tracy, first, just hit the last part that you followed up on. On Yellow Rose, you certainly mentioned the large amount of HBP property, and now you certainly have much more well control there -- wondering how you think about it? In the press release, it said maybe around $30 million-odd; maybe half would go to Yellow Rose, and half or so -- or I don't know if it's half.

But of the $30 million-odd, some would go to the Gulf shelf and some would go to Yellow Rose. How much do you anticipate potentially spending there? And of what you spend there, would it mostly be horizontal wells this year, or vertical?

I would expect most of it to be horizontal activity, Neal. And of course, we're still constantly evaluating our operating margins there. Cost of goods and services is coming down right now. We're seeing good movement in a southerly direction on those costs. But right now, we just want to focus on reducing costs, and analyzing where we're going to drill at next, and how we're going to carry out our longer-term program.

Okay. And then, Tracy, although you don't -- I mean, you're certainly not strapped for cash in the near term, is there a price these days -- in the next month, next quarter -- where you would consider selling Yellow Rose, or is that just something that's not in the plans yet?

There's a price at which I would consider selling every asset in the Company, Neal (laughter). That's always a possibility. Every day, the Company's shares go up for sale, and assets go up for sale, if somebody comes with the right number. So, that's never been an issue. It's not a pride-of-ownership thing.

But right now, we're afforded the luxury of looking at a longer-term picture without short-term pressure on production. We're trying to look at this thing as a 30- to 40-year property, and we're going to have swings in prices and everything.

But the good news, if you look at it from a half-full perspective, is that we'll now be able to source materials in bulk at lower prices, which is what we've been telling the market we were getting ready to accomplish in a development program. We're about well number 15 -- what we thought was a 15- to 20-well horizontal program, so that we can analyze what we'd need for the future. So, hopefully that will make sourcing materials cheaper, and we can prepare for the long run.

That makes sense. Then, last one for you: I know you mentioned in the press release -- just as far as spending -- just really going after the development in those projects you've already started. My question is: Looking at either Big Bend -- I know, gross or so, you guys are estimating a peak rate of over 22,000 barrels; or Dantzler, I think you guys were thinking around [30,000]. Tracy, is that just the initial wells?

The way, when I'm looking at those projects, are there step-out wells? Are there different things that you would consider that would boost -- again, might not change obviously reserves dramatically initially, but could actually add -- given those kind of cash flow rates, are there additional step-out wells or something like that, that you could add around some of these mega projects?

The answer to that is certainly yes. And what we decided to do, along with our operator there, is put the wells on production, gather production data. We do have wells on production. We have room in the infrastructure to add a well at each one of these projects, as I recall.

So, that is the plan. We'll wait and see what production characteristics are, but we're actually -- with the productivity of the wells that we have -- we're a little bit limited at Thunder Hawk right now.

That was what I was going to ask you. So, is it a take-away issue on any of those, or is it something else?

It could be. Right now -- as I recall, Neal, it's about 55,000 barrels a day throughput that we can achieve with initial production. We may be able to increase that later on. We'll just have to see what everybody else is producing across the platform -- where pressures end up, and what the producing characteristics of the wells are. We expect this field -- both of these fields -- to expand.

Certainly a nice problem to have. Thanks, Tracy.

Thank you, sir.

Thank you. Our next question comes from the line of Richard Tullis with Capital One Securities. Please go ahead with your question.

Thanks. Good morning, everyone. Tracy, looking at the CapEx for 2015 -- the deepwater allocation -- what's a rough split-out of that CapEx number by project?

We probably have that -- I don't recall the numbers right off the top of my head. Most of it's going out in the Gulf of Mexico to deepwater, and a little bit to the shelf, but most of it is to the deepwater. I think I gave those numbers earlier, Richard.

Okay. Maybe another way to ask it, Tracy, is: How much is allocated for Big Bend and Dantzler in 2015 to get those projects on?

Oh, it's about $100 million.

Okay. What would be your expectation for facilities and asset retirement obligations, CapEx in 2015, and maybe even looking out to 2016, as well?

We're working on those numbers now; probably around $30 million to $35 million for 2015. I'm not sure about 2016 at this point.

Okay. How quickly do you expect Big Bend and Dantzler to ramp up to that 8,000 to 9,000 barrel a day net number that you had referenced?

I would expect that, from start to finish, it would be somewhere around 60 to 90 days -- expect Dantzler to come on second, Big Bend will come on first, and then we'll level out the production. But start to finish, to get them all online, I would probably assume around 60 days. Could be a little longer, could be a little bit less, but I would assume around 60 days.

Okay. Roughly, how much in proved reserves has been booked thus far for Big Bend and Dantzler on a combined basis?

We had that at around 6 million for Big Bend and --

6 million is the combination of Big Bend and Dantzler.

That's booked proved reserves.

Right. Right. I think that's all I have right now, Tracy. I'll jump back in the queue. Actually, one more: Are you planning to participate in any more Lower Spraberry horizontal wells with your partners in 2015?

I'm not sure; I think probably there may be one or two wells, Richard. I just don't remember.

Okay. And then just lastly, what was your working interest in the UL Mason well -- the No. 2?

It's about a third.

Okay.

Thirty-three and a third. (multiple speakers)

Okay. That's all for me. Thank you.

Thank you, sir.

Thank you. Our next question comes from the line of Noel Parks with Ladenburg Thalmann. Please go ahead with your question.

Good morning.

Good morning, Noel.

Couple of things: Continuing on the UL Mason well -- that was your first Lower Spraberry?

No, it wasn't our first Lower Spraberry. I think we've had two other wells in there so far.

Okay. Got you.

Looking at the deepwater program, with the lead time and everything, I'm not used to thinking much about any changes, as far as costs, once you get rolling. But as a practical matter, do you see -- especially in the non-operated stuff -- any potential for -- I don't know if there could be any compromises on day rates or anything, given how tough the oil environment is? Any thoughts on that?

I think everybody is focusing on reducing costs; certainly our operating partners are as well. We see it in the cost of goods and services. First place you usually see it is not with the drilling rigs or completion rigs because you've already made a contract with them. The cost of goods and services' lag is about six to nine months before we get back to a normal operating margin.

I like to tell people this, and I don't know whether people believe me or not, but our margins at $30 oil were the same as they were at $100 oil. Operating margins for us tend to be around 60% EBITDA margins. Once things level out, then that's about what it gets to be. But I would expect our outside operators, like us, to be focusing on the things that they can effect immediately. A lot of that has to do with transportation -- boats and helicopters; that's our second-largest cost, behind the rig cost.

Got you. Thanks. And as we look at this oil environment -- if you look into second half of 2015 and into your 2016 planning, how different do things look as far as where you deploy your capital? Say, if we're looking at more of a longer-term $50 oil deck, six months from now, versus, say, $60 -- in that $10 range, what projects have the biggest inflection point?

That's a really good question, Noel, but again, remember, that's a function of EBITDA margin. So, while the nominal dollars may be less, what we want to focus on is getting back to a normal margin rate. That's the biggest thing. Even though oil is at $50 a barrel, it's really a question of what your margins are. Then, if oil prices fall, then we will make adjustments to that.

I would expect that what you would see, and continue to see, is reduction in the rig count. I think that's a very important factor. You have to pay attention to that, particularly as it relates to oil production, because it's so much more valuable. The reality is: As the rig rate continues to fall, you set yourself up for at least a bottom, and a potential for going up quicker. So, the faster the rig rate falls, the more likely that you have stabilization and upward price pressure.

Got it. The last one for me: As far as the expenses in the guidance -- just looking at LOE -- looking at the first-quarter run rate compared to the full year, does the guidance anticipate or include cost savings as a foregone conclusion, or are you conservative for now with the potential for maybe the year total to look a little bit better than the first-quarter run rate?

Again, we think that's a function of oil prices. So, that's our best guess that we've given you right now. Hopefully, it would be less than that; but if it went up, then we would expect that would be a function of rising crude prices.

Because certain of -- the middle quarters of the year are a work in progress as we see how things unfold. Is that fair?

I think we're moving pretty quickly to reduce prices as much as we can. I think the service providers understand that. The way it works is: It has to come from our direction first, because if you don't ask, you don't get, and that's a fact. And then, they have the same obligation with their suppliers. So, they have to run it down through their suppliers, too. We have our entire staff is focused on getting this process implemented as soon as possible.

Great. That's all for me. Thanks.

Thank you, sir.

Thank you. Our next question comes from the line of Patrick Rigamer with Global Hunter Securities. Please go ahead with your question.

Good morning. Thanks for taking my call.

You talked about the flexibility in the capital spending budget. I'm just curious, if we do see a recovery in prices later in the year, where would you begin to add capital to the program?

That's a really good question. We'd have to look at what the margins were in the different fields in different areas at the time. I don't really know that I can fully answer that question.

I would expect to first pay out -- work on the things that have the quickest payout. So, that's going to be a function of what the cost of goods and services are going to be. We're making good progress in all of these areas, Patrick. And I think that's probably indicative of everybody realizing that they have to get back in line.

Okay. Thanks.

And then, Dantzler, it seems like maybe that's moving a little bit faster than anticipated, if I'm reading that correctly. I think at the last update, it was a 2016 first production; and now, potential start late 2015. Just curious what's driving that, and what's maybe the critical path here that could flex that into 2015 or 2016?

Critical path are long-lead items. I think we're having some pretty good luck with long-lead items. The next critical path will be installation of the loop and the umbilicals to manage that. So, those are the things that are driving the completions of those wells at this point in time, because the wells are already completed. So, we're just doing the gathering part of it now.

Okay. And then, the last one for me is: You guys are always active in the A&D market. I'd just certainly appreciate your perspective on where the market is now, and how W&T fits in with that? Thank you.

There's always an A&D market, whether prices are up or whether they're down. I know that people -- this is an excellent question, by the way, Patrick. Thank you. I know that people think that when prices go down that that's the best time to go out and buy production or do acquisitions. Well, the acquisition side of it is a little bit tougher. People dig in, and they try to hold on to what they have because they've worked hard to get it. So, there's a little bit of an emotional response there.

Secondly, maybe the acquisitions are more difficult to do, but the merger side of it becomes a little bit more active in these lower-priced environments. So, then it becomes a matter of how you can handle debt -- what your liquidity is? I do see a lot of money on the sides looking at this, and figuring out what they want to do and how they want to perform. I expect that you'll see a lot of activity on land -- more activity on land than you would offshore.

Does W&T have a preference as far as land versus offshore, in this environment?

No, sir; we're just in business to make money.

All right. Thank you very much.

Thank you, sir.

Thank you. Our next question comes from the line of Gail Nicholson with KLR Group. Please go ahead with your question.

Good morning. Looking at the cost savings, do you think you're going to see more cost savings onshore versus offshore? Or do you think it will be pretty similar across the two regions?

That's a really good question, Gail. The first thing that we see offshore is a reduction in the transportation cost for boats and helicopters, which can be substantial. That's already begun. We're having good success with that.

The next thing that we think about is, of course, insurance and labor costs, and the cost for ancillary equipment that we need to do to run the operations, and then lease operating expenses, which are all coming down pretty quick in the Gulf. I don't know that I can say that the Gulf is coming down quicker than it is onshore, because there's a lot of rigs being laid down. So, those costs are coming down pretty quickly as well.

One of the things that we notice is, of course, rig costs onshore are going down very rapidly because they don't have the kind of longer-term contracts that you need for offshore. So, the onshore rig cost is coming down very quickly.

Transportation costs also are going down quickly, as I mentioned. But also, we're seeing some flexibility with the cost of completions and fracs and everything else out in West Texas.

Okay. And then, with the potential of rig rates in the offshore coming down, and you guys have a plethora of prospects and opportunities in the deepwater. Is there any thought to potentially locking in a long-term rig to do deepwater projects in the Gulf of Mexico in this current environment, hoping that there is a recovery? What's your thoughts there?

There is that possibility; and certainly, when we get into these lower-price environments, you start to see the likelihood of longer-term contracts, both for rigs and in transportation. In higher-price environments, nobody is really willing to lock in longer-term contracts. But as we get into this lower-price environment, longer-term projects become more intriguing as a hedge.

And then, looking at the potential for a third well at Ewing Bank, I'm assuming that will probably be similar, cost-wise, around $20 million. Would that be additive to the $200-million budget, or would you re-align funds if you decide to drill that third well?

I think we would probably look at that as an addendum.

And then, just one quick lastly: The dividend being reinstated, is that a combination of improving oil price environment, as well as reduced service costs? Or is it all about margins and where your cash flows are throughout the year?

Yes, it's an all-of-the-above approach. We certainly want to return the dividend. I certainly want to return the dividend. That's how I get a lot of my income, so I'm motivated to do it. But at this point in time, it just makes more sense to suspend the dividend until we get back to a normal operating environment -- cost of goods and services and a little more predictability.

Great. Thank you.

Thank you.

Thank you. Our next question comes from the line of Michael Glick with Johnson Rice. Please go ahead with your question.

Good morning.

Hi, Michael.

Just curious to get your thoughts on hedging, particularly as we start looking at 2016?

2016 is a little bit further out than I think about right now. When you're trying to avoid the alligators, you've got to think about whether you want to really worry about draining the swamp.

But at this point in time, I don't really have any predisposed desire to hedge into 2016. The likelihood that it goes up is greater than the likelihood that it goes down, as far as pricing is concerned. You may see some temporary further bottoming out; I don't know. Again, if I knew, I would have made different preparations and been in a different business.

But the reality is that we're in pretty good shape for liquidity -- this Company is right now. And of course, that could change if prices go down, and continue to stay down. And I think everybody else is in the same boat.

We're not desperate. We use hedging as a tool to protect the things that we need to protect. Right now, we think we have pretty good liquidity. If that changes, then we could think about doing something different later on. I don't know that I necessarily need to go out and hedge anything at this point in time.

Got you. Just on the revolver, any expectations to where that borrowing base goes, post spring redetermination?

We've certainly tossed it around in our shop. I don't think we're ready to talk about that yet. I think we just take a little bit of a wait-and-see effort right now.

Do they give you much credit for Big Bend or Dantzler?

I think we answered that already, in that we have a certain amount of proved reserves, and that we have more potential there. But beyond the proved reserves, banks don't give you a whole lot of credit for probable and possible reserves, or exploratory reserves. They are more proved-reserve-oriented in their borrowing bases, and that's how they lend -- that's why their interest rates are so much lower because they're always the senior secured lender.

I'll just ask about 2016 one more time. The current strip with Big Bend and Dantzler coming online -- you'll have a pretty significant increase in year-over-year cash flow, and your capital commitments will decrease pretty significantly. Just curious what you're initially thinking in terms of capital allocation?

We've already decided what we're going to allocate for capital in the deepwater. It's $100 million-something; and about $100 million of that goes to Big Bend and Dantzler. Oh, I'm sorry, 2016. Excuse me, you're right -- 2016.

No, I don't have a forecast for 2016 here. Most of that capital allocation that we see right now is for 2015. As we come online, we'll make some judgments going forward. I would hope to have the quality problem of having to worry about what we might want to spend in 2016 to expand the program.

But I think that at this point in time, both us and the other operator/non-operators are thinking that we've done the right thing in putting these wells online as soon as we could, and gathering up production data rather than going out and doing a multi-billion-dollar development program with structures. We chose to subsidy complete these wells over to Thunder Hawk, and add to them as we thought it was necessary. So, that's (inaudible) we're just going to stand by and see what happens with what we're doing with these wells, as well as looking at other opportunities to help us build inventory.

Fair enough; thank you very much.

Thank you, sir.

Thank you.

(Operator Instructions)

Our next question comes from the line of Richard Tullis with Capital One Securities. Please go ahead with your question.

Thanks for taking my additional questions. Tracy, looking at year-end 2014 production, what do you estimate your Gulf of Mexico base production decline to be?

Normally we see -- from existing formations, we see about a 15% to 20% annual decline from existing formations. As far as Big Bend and Dantzler, we don't expect that. We expect lower decline rates. We think these are big fields. So, that's how we look at it right now.

Okay. With Big Bend and Dantzler coming online by the beginning of 2016 -- those are mostly oily projects -- what do you think your oil percentage of total production could be by then, versus, say, the 40% in 4Q?

I would think that our percentage of production goes up. I don't have really an accurate handle on that because we're not sure exactly when we'll get back to normal EBITDA margins. But most of the stuff we're working on is oily in nature, just by virtue of the fact that it's just much more valuable.

Okay. And then last question: You had a number of horizontal Permian wells waiting on completion, as of the time of the press release. And some of it is going to wait for lower well cost or completion cost. How do you see the timing of that working out over the course of the year? Do you expect to have all those wells online by year-end 2015?

I don't know if I can say that or not, Richard. Again, we think that the lag period on the cost of goods and services is around six to nine months to get back to normal EBITDA margins. Internally, I think we'll get there a little bit quicker; but traditionally it takes about six to nine months. I'm a little bit reticent to say it's going to be two months or three months or four months, or anything like that. But the way I look at it is that as soon as we get back to normal EBITDA margins, we'll go back to work.

Okay. That's all. Thank you.

Yes. Thank you.

Thank you, ladies and gentlemen. There are no further questions at this time. I would now like to turn the floor back over to Mr. Krohn for closing remarks.

I'm done. Thank you very much. We'll talk to you next quarter, if not sooner.

Ladies and gentlemen, this does conclude our teleconference for today. You may disconnect your lines at this time. Thank you for your participation, and have a wonderful day.