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Energy XXI (Bermuda) Limited (NASDAQ:EXXI)

Q4 2014 Earnings Conference Call

August 14, 2014 10:00 a.m. ET

Executives

John Daniel Schiller - Chairman and Chief Executive Officer

David West Griffin - Chief Financial Officer

Stewart Lawrence – Senior Vice President of Investor Relations & Communications

Analysts

Stephen Berman – Canaccord Genuity

Michael Glick - Johnson Rice & Company

David Deckelbaum – KeyBanc Capital Markets

Richard Tullis - Capital One Securities

Dan McSpirit – BMO Capital Markets

Brian Foote - Clarkson Capital Markets

Christopher McDougall - Westlake Securities

Chad Mabry - MLV & Company

Joan Lappin – Gramercy Capital

Sarah Hunt – Alpine Funds

Operator

Good day, ladies and gentlemen, and welcome to Energy XXI Fiscal 2014 Year End Conference Call. At this time all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will follow at that time. (Operator Instructions) As a reminder, this conference is being recorded.

I'd now like to introduce your host for today’s conference, Stewart Lawrence, Senior Vice President, Investor Relations. Please go ahead.

Stewart Lawrence

Thank you, Kate and welcome to the call, everyone. Presenting today, we have John Schiller, Chairman and CEO; and West Griffin, Chief Financial Officer. We'll be available to answer your questions after the call as usual.

Before we get started, I need to remind everyone that our remarks today, including answers to your questions, include statements that we believe to be forward-looking statements. These forward-looking statements are subject to risks and uncertainties that could cause actual results to be materially different from those currently anticipated. Those risks include, among others, matters described in our earnings release issued yesterday and in our public filings. We disclaim any obligation to update these forward-looking statements. While the company believes these forward-looking statements are reasonable, they are subject to factors such as: commodity prices, competition, technology and environmental and regulatory compliance. Our drilling schedules, capital plans and other factors may cause our results to differ materially. I urge you to read our 10-K and our latest 10-Q to become better familiar with these risks and our company.

Now I'll turn the call over to John.

John Schiller

Thanks, Stewart, and welcome, everyone. It was a busy year for Energy XXI, especially on the M&A front. The EPL deal represents an important inflection point for us, not just because it was our first corporate merger, but because it elevated Energy XXI to a new level. From our first acquisition, the Marlin properties in April 2006 through the EPL transaction last quarter, we’ve built a company that operates 10 of the largest oil fields on the Gulf of Mexico shelf and employs about 500 people.

Slide 4 shows our production growth over the past six years, along with this year’s forecast. Year-over-year in fiscal ’14 our total production grew 4% while oil production grew 6$. We plan to deliver more than 44,000 barrels of oil per day this year which would be roughly a 50% increase year-over-year. We’ve celebrated some significant milestones since forming the company in 2005 and also had our share of growing pains. Today we feel confident we have the right assets, the right people and the right processes in place to deliver results that drive shareholder value.

Let’s look at the detail in last night’s release first, then take a look forward to what should be another profitable year for the company. Our fourth quarter and yearend financials were released yesterday evening. Production came in ahead of guidance for the quarter, with a higher percentage of oil than forecast. We also reported reserves last night. We increased reserves once again as we have every year since the company was formed. That gives us a six-year annual growth rate of nearly 40%. And because reserve additions have focused on oil and the value of those reserves has grown at an even higher rate of almost 50% a year.

On Slide 6 you’ll see the EPL acquisition was a primary driver of growth following the prior year when organic conditions lifted reserves nearly 50%. Still, organic additions in fiscal ‘14 net of revisions, added 12 million barrels of oil, giving us a 72% organic reserve replacement overall. More importantly, we replaced 124% of our production organically. That’s worth repeating because oil is really what matters in this value equation. Oil is the sole focus of our core joint program. And we successfully grew our oil reserves organically in addition to the 53 million barrels of oil that we acquired in the EPL deal. Those oil barrels drove our PV-10 value to $7.6 billion on pre-reserved and $14.6 billion on a 3-P basis.

In the addendum to the presentation online, you can find the 3-P reserve data as well as additional details on reserves by area. Having acquired the EPL assets right before our year end, our teams were unable to review each of their reservoirs. So we believe there is still potential for more upside booking of the 3-Ps this year. Now let’s have West to cover the financials for the quarter and year end.

West Griffin

Thanks John. As John mentioned, our oil production averaged approximately 32,000 barrels a day for the fourth quarter. Both oil and overall production came in ahead of guidance. Full year production averaged 45,000 barrels a day of which 67% were liquids.

Net income for the quarter was impacted by $10.6 million of non-recurring charges. These charges were mostly related to acquisition divestiture activities and are embedded in G&A.

Effective income tax rates were higher this quarter, mainly because of the non-deductibility of those acquisition divestiture expenses. However, Energy XXI does not expect to be a cash taxpayer in the near future.

Now let’s look at the detail on a BOE basis. Realized prices for the quarter, including hedges, were $99.67 for oil and $4.45 for gas with our realized price for BOE at $77.28, the highest price for the fiscal year, even factoring in hedge losses. Insurance expenses averaged $1.99 per barrel. The bottom line is that we continued to generate EBITDA well north of $40 a barrel. As a result of the EPL acquisition, we leveraged the balance sheet to around 67%.

As seen in Slide 10, we have a track record of leveraging up for acquisitions, then paying down debt to our target level of 40% to 60%. Our goal is to do it again. In addition to refinancing the 9.25% notes later this year to strengthen the balance sheet.

Guidance is something we have not provided in the past, but we issued our first guidance in last night’s release which is shown on Slide 11. Fiscal first quarter production should average between 57,000 and 60,000 barrels a day, with approximately 71% being oil. Full year production guidance is 59,000 to 64,000 BOE. Guidance assumes about 10% production downtime. Oil guidance for the year is 42,000 to 47,000 barrels a day compared with where we entered the year at around 42,000 barrels a day. On an annual basis, oil production should grow 40% to 50% above our fiscal ’14 annual oil volumes. Those volumes should deliver the EBITDA ranges included in the chart based on the varying commodity price assumptions. Those price assumptions represent our realized prices, including the impact of hedges and differentials. So for example, a $95 WTI market price could very well equal $100 realized price.

Now I'll turn this call back over to John to provide additional updates.

John Schiller

Thanks West. Let’s review the capital program on the details provided on Slide 13. Today we have eight rigs working on the shelf, highlighting the fact that our capital program is focused on development drilling, with a goal of 30 new wells coming online this fiscal year, compared to 17 last year. Our $875 million budget should allow us to average six rigs running this fiscal year, once again focusing on all production. As you can see on the slide, over 70% of our capital budget this year is focused on development, demonstrating our continued focus on driving production and cash flow from lower risk projects. And that number is even higher if you include the capitalized G&A. Most of that is also directed to development.

The facility spend in this year is designed to help optimize production by reducing back pressure in our production facilities in the field and throughout our pipeline system. This will be in the form of gas and water handling equipment as well as pipeline to help alleviate back pressure and provide greater flow insurance from our platforms ashore. The majority of this work will be involved in the West Delta 73 and West Delta 30 areas.

We continued to integrate EPL into Energy XXI and we’ve seen savings ahead of what we originally expected as shown on slide 14. A large piece of those savings is on insurance where we expected to see initial savings of $15 million and actual savings we’re in excess of $25 million when we renewed our insurance in June.

G&A is another area where we’re already capturing significant synergies. We have the teams integrated now and have made most of the cuts needed to right size the operation support and administrative staff. Today the annualized expected G&A savings should exceed $15 million compared with the $7.5 million discussed originally. In LOE, we expect savings from the economies of scale. We’re optimizing the use of boats and helicopters, adjusting contracts with service providers and combining shore based operations at Grand Isle and on Fourchon. In total, we should save more than $50 million on lease operating expenses in fiscal 2015, triple what we promised with the potential for more going forward.

In summary our goals are to increase oil production through low risk development drilling while driving down cost, all which help to increase cash flow to strengthen the balance sheet. With the EPL acquisition, we’ve created an unmatched asset base that provides opportunity to achieve these goals and we have formed the teams and challenged them to execute on the program. These are the reasons we believe the future is bright for Energy XXI, our employees and our shareholders.

This concludes my comments. Operator, you can open the line for questions please.

Question and Answer Session

Operator

Thank you. (Operator instructions). Our first question comes from line of Steve Berman with Canaccord. Your line is open.

Stephen Berman – Canaccord Genuity

Good morning everyone. John, can you elaborate on the guidance a little? If I back out the roughly 20,000 BOE at David that EPL was doing at the time of the acquisition, you’re kind of at the 40,000 to 45,000 range which is what you guys were doing. So I’m just trying to get a better handle on organic growth. And I don’t know, maybe this guidance is ultra-conservative. Can you kind of tie that all together for me?

John Schiller

Steve, I mean I’m not going to spend a lot of time concentrating on the two parts because that’s not how we’re running it, but A, yes. Look, we’re going to put out a number there that we’re going to feel very comfortable \ we’re going to make. B, we talked about 62,000 in current run rate. That was our current run rate. It still is in terms of capacity. We had a 3% downtime day that day. We’re running at about 10%, about half of which we can control, half of which is pipelines doing their summer pig maintenance, pipeline maintenance, running pigs things like that, A lot of it is just the hot weather shutting down and rotating equipment. And some of it is self-induced with rig activity we have where when we shut down wells, platforms in order to do certain rig activities, it’s 3 and 4 and 5 days before we’re back up to that totally optimized production.

I can’t emphasis enough what it takes to optimize artificial gas lifted production. We do it really well, but it takes a while to do. It’s not like you just flip a light switch on and off and you have the volumes back and then six days later we’re making another case and running -- shutting that same field down. So, we’re building ourselves some leeway around there. Our ability to produce is higher than it’s ever been on a combined basis and it continues to grow. The well program has been delivering. We’ve just got to deal with what I addressed in my opening comments, facilities, back pressures and allow the wells to do what they’re capable of.

Stephen Berman – Canaccord Genuity

The 30 development wells in the budget at this point, do you know how many of those will be horizontals?

John Schiller

We do. Anybody got the number?

West Griffin

Got a fee of roughly half.

John Schiller

Right around half, Steve.

Stephen Berman – Canaccord Genuity

Okay. I’m sorry, go ahead.

John Schiller

I’d say obviously most of those are in the West Delta area,. Wells outside the West Delta area will probably not be as many horizontals.

Stephen Berman – Canaccord Genuity

Last one and I’ll get back in the queue. The $33 million in the CapEx budget for exploration seems low. I assume that can go up once the seismic is in house and processed et cetera. Can you talk a little bit about the timeline with all that?

John Schiller

I think the thing I would remind you is we have two big seismic shoots. One that Energy XXI had going on in the main pass area. As we get that data in there may be some wells late come to year 2015 that come out of that, summer 2015. The EPL shoot is just now starting. So wells are actually getting drilled out of that, Andre, two years?

Andre Broussard

Yeah, year and a half to two years.

John Schiller

Year and a half to two years away. So what we have in there is mainly OBO associated primarily in the Main Pass area with the stuff that Fieldwood is doing. One of those wells has already been drilled and being completed. It’s a good well and that’s where the majority of the exploration money is going to.

Operator

Our next question comes from the line of Michael Glick with Johnson Rice. Your line is open.

Michael Glick - Johnson Rice & Company

Morning guys. Just looking at CapEx and your EBITDA guidance, it looks likes at a $100 oil you’ll be closer to cash flow neutral for the year. Just curious to hear your thought on what the plan is to bring that leverage down to that 40% to 60% target?

John Schiller

Yeah. I think the key things are going to be driving more synergies. I think we are still as we look at LOE and drawing capital both, we across the board Keith and Pam both feel like there’s a lot of room there to drive down cost. We are seeing it already as we’ve flexed our muscles. We are seeing 10% and 12% reductions in some of the service costs. So I think there’s implied synergies that you won’t see in there, but we’ll start seeing them. Some this quarter, a lot by the second quarter.

Michael Glick - Johnson Rice & Company

Okay. And then Any updated thoughts on non-core asset sales or joint ventures?

John Schiller

Yes. I would tell you that I think one of the lessons I always learn from Larry at Devon is he did a great job of doing acquisitions and selling off the lesser pieces of it so that he built a really great core set of assets. So I would expect us to do something similar to that on some of the non-core assets to see a package go out. The time is probably late this calendar year, most likely early next calendar year to do it right. But I think you will see us do that and I will tell you that we continue to have talks around the JV and with the new company and everything else we’ll see where that goes.

Michael Glick - Johnson Rice & Company

Got it. And then just looking at the capital budget, how should we think about the split? Maybe first half, second half on the development side?

John Schiller

60% is going to be in the first six months.

Michael Glick - Johnson Rice & Company

And the facility spend?

John Schiller

And Michael maybe a little bit more detail than that. Maybe even 70% on the drilling side will be in the first six months. But the facilities will be a little bit more back weighted into the second half of the year.

Operator

Our next question comes from the line of David Deckelbaum with KeyBanc. Your line is open.

David Deckelbaum – KeyBanc Capital Markets

Thanks for taking my questions, guys. John, you talked about I think in the guidance or West said using 10% downtime. I guess is that the third party downtime that you are seeing I guess is in that $59,000 a day number in July. Do you have any visibility around what you could reasonably expect? Because I think you had been at a point last year where you weren’t seeing any downtime at least before the EPL deal. Is there any color that you can provide us on what you are thinking around getting to that 10% number?

John Schiller

Yeah. Look, I think pre-EPL when we were getting things going the way we wanted at Energy XXI we were working ourselves back towards 6% or 7% downtime and feeling pretty good about that. We think realistically5% is sort of the target low end of what you can do on downtime. Obviously as I said when you are running rigs, that creates more problems. So what we have to do is make sure all the fields where the rigs aren’t running are having 5% or less downtime and where the rigs are running just continue to do what we’ve been focusing on which is not have a rig shut us and then a facilities project come in two days later and shut us in. I’m doing a much better job in coordinating that. If you remember when we have big activities in Energy XXI or sometimes there where we suffered with 12% and 14% downtime. I would say that improvement is of course better communication across the board in coordinating the projects that are going on out there so they’re in sync.

David Deckelbaum – KeyBanc Capital Markets

Okay. I guess, can you give any detail on the facility spend, the $132 million this year? Can you tie that back to perhaps future productive capacity?

John Schiller

Sure. I’ll tell you, one of the big ones about $40 million of it is after we took over Exxon, there was a pipeline out of Grand Isle field itself that went to Grand Isle base that we knew and they knew was getting very thin walled. I guess within the first year we had a slight spill on it, a leak. And the government came in and said, we don’t want you flowing to that anymore. We rerouted all of Garand Isle and West Delta 30 production back to West Delta 73 and just have one line coming to shore now to the Grand Isle base. That’s the cause of a lot of our back pressure. We are moving a lot of fluids that used not to go through West Delta 73 plus the results of our horizontal wells moving a lot of fluid. And so we need to get that production out of the West Delta 73 flow loop and pipeline.

So a big part of that project is re-laying that existing line and giving us -- what it will do is bring all of the oil in the Grand Isle through two different angles, two different pipelines which will give us more flexibility in case something happens down the road. We expect that to be around a 1,500 barrel base impact on production as a result of that project. And then some of the other things you’ll eventually out of that is it will allow to drive the EPL portion of West Delta 30 into that system which will give them two outlets out of those assets and again bring all the well to a place where we can do a little better marketing job, control of everything at the Grand Isle facility. That’s the biggest one. Another 20 million or so is within West Delta 73 proper between the three or four platforms that are out there, upgrading water handling so we send less water to the beach and more disposed of in the field and bypassing where again that total production is flowing across some platforms and causing issues with back pressure.

David Deckelbaum – KeyBanc Capital Markets

That’s helpful and if I could just wager one more I guess is I think you just discussed some of the non-core asset sales. And I think this year with the CapEx budget and the growth that you have laid out, if oil prices hang in there, it could be free cash neutral. If you want to get your leverage metric down, are you looking at anything else? I know you had mentioned before and perhaps looking for monetizing a portion of the ultra-deep interests. Is that on the table? How should we think about timeline with that and just your thoughts on that?

John Schiller

Yeah. That is on the table. I would say that obviously doing a merger set things back and we had to step back from that and reevaluate everything that was on the table in terms of the new assets. But I do think that if we are going to do something there it’s sooner rather than later.

Operator

Our next question comes from the line of Richard Tullis with Capital One. Your line is open.

Richard Tullis - Capital One Securities

Good morning everyone. John, looking at the current rig schedule, so you currently have eight rigs running and I guess the CapEx is more front end weighted in the fiscal year. How do you see the rig count in the second half of the year? Is that running say four to five rigs?

John Schiller

Yeah. Actually we average six for the year and second half of the year we got under four rigs.

Richard Tullis - Capital One Securities

Okay. And West, what do you see as the go forward G&A run rate? What’s a good, clean number there?

West Griffin

Yeah. Our G&A you are going to basically see that – we’re going to continue to have a little bleed through because of the transition elements this quarter. And then you are going to start seeing that come on down as we realize the consolidation benefits. We still have a number of folks that are setup for transition and they’ll be transitioning out between now and December this year. The first clean quarter you are really going to get on the G&A is going to be your March quarter, but you are going to be trending on down in the September and December quarters.

Richard Tullis - Capital One Securities

Okay. And the DD&A rate, is the number for this past quarter a pretty good number to use on a go forward basis as well?

West Griffin

Yeah.

Richard Tullis - Capital One Securities

Okay. As far as the deep shelf drilling goes, I know you talked about it a little bit with some exploration money dedicated there. What’s your view on that play where we are now and what’s the potential there maybe even to expand it this fiscal year and into fiscal year 2016?

John Schiller

Yeah. We are not the operator so I’ll keep the comment short. But I think we have a lot of faith in it. We put money there obviously testing the Highlander well here in early October probably is an important part of that. We like everything we’ve seen there. We got a lot more data on that well than we have anywhere else and we’re progressing smoothly on that completion. We’re going to spud the furthest Gate East Well here this summer, and that’s a (Yeager) prospect coming off of what we have with Chevron at Lineham Creek. And I think the beauty of the [Yeager] play, as you get shallower and shallower you start talking about targets of 24,000 where you can conventionally go through more normal equipment and use 20,000 pound equipment if things work right for you. So the play is moving onshore right now, cheaper drilling, quicker production times and hopefully even some conventional equipment so that we’re not doing 25,000 completions everywhere.

Operator

Our next question comes from the line of Dan McSpirit with BMO Capital Markets. Your line is open.

Dan McSpirit – BMO Capital Markets

Thank you, folks. Good morning. Regarding non-core asset sales, what assets are considered non-core?

John Schiller

I would tell you that a lot of Dan of our non-operated stuff, we’ve probably got 40 fields I think in the neighborhood of small pieces and something like that. And then I think probably you look at your operations and you try and find your one core field. It may be something in the far West, far East, something that makes the overall package attractive. It's probably a – if I just ballpark parameters for you, 5,000 to 7,000 barrel a day package, somewhere in there.

Dan McSpirit – BMO Capital Markets

Okay. Great. And you gave us what a successful test of Lomond North means in terms of CapEx. What does that mean for production growth or is that captured in the high end of guidance?

John Schiller

Yeah. The impact this year on production is very small. When you start bringing on a second development well, then it starts meaning more material volumes to us obviously.

Dan McSpirit – BMO Capital Markets

And then if I may, just based on guidance that has been laid out, where do you see leverage by the end of this year, fiscal year end?

West Griffin

Yeah. The leverage is going to decline a little bit about 2% relative to where it is and is largely due to an increase in book equity as opposed to reducing debt, but a little bit we’re going to be pretty close to flat on the debt side.

John Schiller

That we accelerated over the next year cash flow we’re building up this year.

West Griffin

Correct. And so basically what's happening this year is we’re ramping up our production, and once we get up to a higher level of production, you can see as if we want to just to hold that production we can cash flow very strongly to pay down debt and accelerate the debt pay down.

Dan McSpirit – BMO Capital Markets

Okay. So, just looking at long term debt to EBITDA, what did you calculate for the end of fourth quarter pro forma for the acquisition and is that held constant or do you see that not changing rather for the balance of this year?

West Griffin

At the end of June we were at 67%. That’s total GAAP and that should decline 2 to 3 percentage points over the course of the year.

Dan McSpirit – BMO Capital Markets

Okay. And then lastly here, what's the base decline rate today? And is that expected to change over time? That is how can it be reduced?

John Schiller

Yeah. I think Dan that the base decline rate is sort of in the20% all-in, 20%, 22% all-in range. We’ve got two key portions as we’ve talked about. If you look at the reservoirs that have been on for more than three years and the wells that have on in the same reservoir for more than three years, we’re sort of in the 11% to 14% -- 11% to 13% decline. What we have to deal with is the new wells we bring on, we hold them flat for X amount of time. Some of them come on and go in decline with water coming in day one. And that’s the one that’s a little bit harder to predict in your base declines. When you look at for instance some of the negative oil revisions, they came from wells that we brought on that were doing good, started making water. You had volumetric support, but as you went through the year, there are declines before they started flattening out or such that you couldn’t keep supporting the reserves right now. So you have to move the volumetric piece into a 2-P portion. And we typically see those wells leveling off then go onto that shallower decline.

Operator

Our next question comes from the line of Brian Foote with Clarkson. Your line is open.

Brian Foote - Clarkson Capital Markets

Yes. Hi. It's Brian Foote from Clarkson. Building on your answer, West to Dan’s question, within your forecast is production growth for 2015 and the resulting EBITDAX and cash flow. What will the 2016 and beyond leverage reduction look like? If it’s a couple percent this fiscal year assuming your production goes according to plan, what would the ‘16 and ‘17 reduction look like as a percentage of debt to capital?

West Griffin

It really depends obviously on what we decide to do with respect to how much growth we want to have in the next years. But for example if we just decided to hold everything flat, you could easily see that be below 60% within the two years.

Brian Foote - Clarkson Capital Markets

And that’s assuming the mid-point or what end of your range in terms of the resulting EBITDA?

West Griffin

The midpoint would be good.

Operator

Our next question comes from the line of Christopher McDougall with Westlake Securities. Your line is open.

Christopher McDougall - Westlake Securities

Yes, thanks for taking the question. Getting back to the non-core assets sales, John, you had mentioned 5,000 to 7, 000 barrels a day a package. Is that on the BOE or barrels of oil basis that you are thinking about?

John Schiller

That’s a BOE.

Christopher McDougall - Westlake Securities

Okay. And then, West back on the leverage question for fiscal year 2016, what is your assumed maintenance CapEx to hold production flat at the exit rate for this year that would be your deleverage scenario?

West Griffin

Yeah. The whole production is basically flat. You are looking at somewhere around $400 million-ish, maybe 250, something like that. .

Christopher McDougall - Westlake Securities

Thanks. And John stepping back -- for a long time we’ve had the enterprise value of the firm significantly below PV-10 of even the proved reserves here .And I’d love to hear any thoughts you have on what the market is maybe missing versus the reserves and get a little bit more color on the reserve report. Some things I was wondering is what the timing for those PV-10 numbers. So how much of it is attributable to production over the next five years versus beyond that and what the assumed production rate changes are for the next few years that go into that reserve report number?

John Schiller

By definition, everything that’s in our reserve report particularly on the PUDs have to be drilled in the next five years. So the capital in that plan from a 1-P standpoint is over the next five years and you can see about 40% of the value is in the PUD. So obviously we have to be drilling wells and bringing them on, but there’s no mass acceleration like that. The way you book reserves today is pretty much assuming a rig program similar to what you’ve been running. So a four to six rig program is what’s invested in there to drill and develop all of our crude reserves. What do I think the Street misses? I think that there’s so much emphasis on the production and the basic belief that the value can’t be achieved unless you increase production.

While there’s some truth to that, it’s all a matter of how you ramp it up and when you ramp it up. And we are doing the right things. We are dealing with issues in the field to make sure we can produce more out of these assets and then we’ll continue to drill and grow. And that’s all you can fundamentally do. The thing we know is oil is there. It’s not going anywhere. It’s there, whether we are talking $65 and $70 oil or whether we are talking $140 oil. so we’ve got a lot of solid projects. We are going to keep executing them and we are going to execute them -- the majority of them by what gives us most money while we’re in that field with a rig.

Operator

Our next question comes from the line of Chad Mabry with MLV and Company. Your line is open.

Chad Mabry - MLV & Company

Thanks, a question on reserves, looking at the report, it looks like we had 8.5 million barrels of negative revisions. I guess first could you split that between performance and price related or is it easier just to provide some general color on the ride down there?

John Schiller

Yeah. I think I’ll just do general color. 5 million barrel of it roughly is in two big gas fields, the Cote de Mer which is a well we drilled years, went off production. It had a fairly large updip PUD to it, but today’s gas environment and even more important with how we’re allocating capital, we couldn’t see allocating capital to that well. So it went off the schedule. Similar thing at Bayou Carlin where we had a PUD booked there. If you follow us, we drilled a well a little over a year ago there. As we looked at that, the fact of what we’re trying to do there is get a 3D shoot shot. We’re having success with some partners right now that we think will come in with us on that. That was another area where we dropped the PUD. So, while it looked big on the reserve numbers, the impact on value was very low because it was primarily gas.

On the oil side, those were typically kind of what I alluded to earlier on, some of our wells that we brought on in the last couple of years, they got hit with bigger declines than we thought they would early on. Ended up with performance revisions, Most of those reserves went into 2-P because volumetrically everything looks like it’s there. We’ve just got to deal with the same thing we’ve been talking about. If you increase back pressure in a field from 150 pounds to 300 pounds, that’s a significant impact on how much each one of your wells will flow and it changes the decline characteristics of the well. While the capacity of the well is still there, if you can flow at hundred, human nature is we want to take the reserves down. And so that’s mostly what we’re dealing with on revisions. I mean year, every once in a while we’re going to have a well that doesn’t perform as well as we think it will, but a lot of it is tied back to just overall facilities issues and back pressure.

Chad Mabry - MLV & Company

Okay, that’s very helpful. Thank you. And then on the debt or I guess the leverage question, just curious if the dividend there is on the table in that discussion?

John Schiller

I think we still feel very comfortable with the dividend. I don’t see that going away any time soon.

Operator

Our next question comes from the line of Joan Lappin with Gramercy Capital. Your line is open.

Operator

Our next question comes from line of f Steve Berman with Canaccord. Your line is open.

Stephen Berman – Canaccord Genuity

Maybe a question for West, just to give us some ideas of the synergies in cost savings. What kind of LOE per BOE is baked into your EBITDA guidance for fiscal 2015?

West Griffin

Basically the direct LOE per BOE in the guidance is right at about a little less than $18 a barrel.

Stephen Berman – Canaccord Genuity

Right. And what about the other two components, the work over maintenance and the insurance?

West Griffin

the work over expense and maintenance I would expect that to be more or less in line with kind of what you’ve seen on a dollar per BOE, what you’ve seen on an historical basis. And that’s pretty much what we have baked in there. And then on the insurance side, that number is on a dollar per BOE basis is right about -- call it $4.5 or so, $4.25, $4.5 a barrel.

John Schiller

Not for insurance

West Griffin

No. I’m sorry.

John Schiller

$1.5 for insurance.

West Griffin

I’m sorry. I misspoke on that. I was looking at the wrong thing.

Stephen Berman – Canaccord Genuity

$1.5?

John Schiller

$1.5 for insurance Steve, yeah.

Operator

(Operator instructions) Our next question comes from line of Joan Lappin with Gramercy Capital. Your line is open

Joan Lappin – Gramercy Capital

Can you hear me?

John Schiller

Yes, we can Joan.

Joan Lappin – Gramercy Capital

Okay, Because, I was asking the same question a minute ago. I guess I’m distressed as others are with your costs somehow -- I mean even G&A has gone up dramatically with no real increase in production over a three year period. And so I’m wondering what kind of things are buried in there that caused that to happen. Did you have a big write off from this acquisition you didn’t pursue in the Far East? I just don’t quite understand what happened. And then I have two other questions, one of which is where are all these BOPs going to be used that have been ordered for the ultra-deep? And then third, is horizontal drilling turning out not to be the panacea you thought it was a couple of years ago in terms of the rates at which these wells are falling off?

John Schiller

First of all, horizontal drilling is delivering everything that we thought it would. We are actually – when you look at the wells we’ve drilled to date against the simulation performance, they are doing better. So they’re not really our follow up issues. They create issues because they move so much volume and pressure they affect other wells, but they’re performing as we thought. BOPs for the ultra-deep is something that you’ve got to talk to FCX. They have plans and they’re paying for things. But I think they’re going to drill – we’re going to prick up a second well, a second rig and drill another onshore well there in their game plan. G&A itself, yeah, there’s obviously some M&A costs associated with this deal in there. There’s also more people at the company that we ran very lean and mean. We took a look at the size we were. We started adding people to help with things like doing internal reserves and working our facilities and working our production volumes. And that’s been the main culprit of G&A.

Joan Lappin - Gramercy Capital

And that’s it? It's just we added a bunch of people?

John Schiller

Over up to 500 people, Joan.

Joan Lappin - Gramercy Capital

I understand. But I guess also we can say that the first number of years it's like every well you drilled was a hit. And the last period, it's like every well wasn’t a hit. So some of that is just the normal course of your being in the industry you’re in, just like for us, not everybody picks stocks that go up. But I don’t know. Somebody asked earlier, why are your estimates so conservative or so low ball other than we’ve got to beat them, but there is this basic question of why things haven’t been moving along in the last long while. It's a lot of quarters now.

John Schiller

I think, Joan I talked about in the opening comments and I’ll refresh to close with and said look, we went through growing pains. When you start a company from scratch, you don’t get to draft the whole 18 with you day one. Not everybody wants to leave a good paying job and go take a chance in a company that’s starting from scratch. If you look at the management committee we have in place today, you look at the changes we’ve made there with Antonio de Pinho coming on board, with Perrin Roller running our drilling, with Keith Acker running our production, and now Andre Broussard over our exploitation and exploration effort. I think we’ve continued to improve the staff across the board. And that’s what you have to do as you go through and get bigger. And we’ve got the right guys in place. You can’t turn a ship this size on a dime, but I feel more confident than I have ever felt about the assets we have, the people we have and where we go from here. That’s all we can do is go out there and execute and prove it to you. That’s what we need to do and we’re going to do.

Operator

Our next question comes from the line of Sarah Hunt with the Alpine Funds. Your line is open.

Sarah Hunt – Alpine Funds

Good morning gentlemen. I think to possibly put this in a different way, the question from the investment side of the table is if the acquisition was going to end up being more costly, and I understand it from a production standpoint there’s a lot of things that are not in your control. It might have been better to tell investors that it was going to be up in the air than sort of have this quarter after quarter where we’re kind of struggling. We understand the net asset value, but we’re kind of struggling with the operations. So I think that that’s kind of the frustration that I was hearing from the previous caller because I'm sharing it as well. So it's more also about how you end up communicating that to us, and I think right now everyone is feeling a little bit stuck especially if we’ve been involved in the stock for the last several months.

John Schiller

Yeah, I hear you. So look, I've done a lot of mergers in my life. I will tell you that the integration on this deal has gone as seamless and smoothly as any deal we’ve done. In the field it takes longer. We still operate fields out there as EPL and as Energy XXI, different spill plans, different everything until the government gives approval and we become the operator of record and all that. And so there are certain things you can impact, certain things you can’t. West gave a great analogy last night when talking about this. When we bought Exxon, we were six months before we took over those fields and they all continued in decline before we got in there and started turning everything around. And we announced that we bought 20, 000 barrels and by the time we took it over we were operating about 16, 5. The same thing we have to go through here, we are making a lot of improvements very quickly on the cost side. Stepping in on the operation performance is not quite as quick and it’s compounded by the amount of rigs we are running. It’s really as simple as that, but we know where the issues are. It’s you optimize production and you reduce back pressure and we will make a lot of fluids and a lot of oil.

Sarah Hunt – Alpine Funds

I wouldn’t want you to run a field in a way that would just push your production and damage the field, but it’s more about a communication issue as you go through quarterly to say hey, we are looking at some places and we are seeing some wrinkles. Or maybe in the interim saying, the government asked us to switch moving production from this place to that place and that’s going to have an impact. It’s the surprise factor I think that the investment side is struggling with at the moment.

John Schiller

I hear you, I hear that. We made the number we thought we would make this quarter. We’ve given you guidance that we feel good that we can make. We’re talking -- the good thing out of all this is we are talking a little bit more high level and less well by well which is where we need to be because we are in a business where we are probably going to drill nine or eight good wells out of 10, but the well we drill are going to get our numbers because some are better than we expect, some are less, but on the whole we are getting the expected results from our wells, both in terms of production and reserves. And that’s what this game is about. We are going to continue to work on communicating better with you. This is the first time we’ve done guidance which I take that to be a big step towards communicating better since we’ve never actually given guidance per se. And I think you’ll see that approach across the board. You are going to see me less on the road and a whole lot more time in the office here to get this thing turned around and that’s where our focus is.

Operator

And I’d like to turn the call back to Mr. Schiller for closing remarks.

John Schiller

All right, thanks everybody, appreciate you being on the call. I want to take a couple of more things. We hear your concerns. We hear your angst. We hear your reaction on stock price and we are all are large shareholders in this company and we feel that pain personally every time something goes the opposite way. So, we are committed. As I said earlier we have a great team and I have full expectations that we are going to achieve the results we want to achieve. I want to make one other announcement today, Ben Marchive, who is our Chief Operating Officer, who’s been a boss to me, a mentor, a friend and someone that’s been with us from the early days of Energy XXI, is going to retire after 33 years in the business, effective October 1. So we will move on from there. Antonio will run the E&P effort. The production operations and drilling operations and safety will come to me directly in the interim. And I think you’ll see us continue to go on and deliver the results we expect to deliver. And so with that I want to thank Ben for the service to the company as he came out of retirement to help us grow this thing. You’ve done a great job there and his legacy will be a big part of the company. Thanks everybody for joining us today.

Operator

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a good day.

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Source: Energy XXI (Bermuda) Limited's (EXXI) CEO John Schiller on Q4 2014 Results - Earnings Call Transcript
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