Executives
T. Paul Bulmahn – Chairman of the Board & President
Albert L. Reese, Jr. – Chief Financial Officer
Leland E. Tate – Chief Operations Officer
Analysts
Neal Dingmann – Dahlman Rose & Co.
Sven Del Pozo - CK Cooper & Company
Leo P. Mariani – RBC Capital Markets
Ronald Mills – Johnson Rice & Company
David Snow – Energy Equities
Stephen Berman – Pritchard Capital Partners, LLC
Phil McPherson – Global Hunter Securities
Richard Tullis – Capital One
Joan E. Lappin – Gramercy Capital Management Corp.
Rehan Rashid – Friedman, Billings, Ramsey & Co.
ATP Oil & Gas Corporation (ATPG) Q4 2007 Earnings Call March 3, 2008 11:00 AM ET
Operator
Good day and welcome to the ATP Oil & Gas Corporation fourth quarter and year end of 2007 results conference call. Today’s call is being recorded and all participants are in a listen only mode. At the request of the company we will open the conference up to questions and answers after the presentation. I will now turn the call over to T. Paul Bulmahn, Chairman and President of ATP Oil and Gas Corporation. Please go ahead sir.
T. Paul Bulmahn
Thank you each of you for joining us at the ATP Oil and Gas Corporation year end 2007 results conference call. My name again is Paul Bulmahn, Chairman and President of ATP oil and gas corporation and joining with me today are Leland Tate, our Chief Operations Officer and Al Reese, our Chief Financial Officer. A press release reporting our fourth quarter and year end 2007 results was issued this morning. You may be reminded that this conference call is subject to the Safe Harbor language included in our press release and that your questions and answers may be entertained shortly.
On November 3, 2005 ATPG stock closed at $35.16 per share. In 2005 we had annual production of 19.9 billion cubic feet, we had proved reserves of $2.7 billion pre-tax PV10 and we had annual revenues of $146.7 million with a net loss available to common shareholders of $12.6 million. Today, in March, 2008 our annual production for 2007 was 64 billion cubic feet and APT’s fourth quarter production of 20.2 billion cubic feet exceed the entire annual production of 19.9 billion cubic feet in 2005. Today we have proved and probable reserve of $5.3 billion pre-tax PV10 value with proved reserves alone of $3.5 billion pre-tax PV10 and for 2007 we had annual revenues of $599.3 million with annual net income available to common shareholders of $48.6 million. Again, fourth quarter revenues alone of $205.7 million exceeded the entire revenue of 2005 of $146.7 million and our share price closed Friday at $35 and change.
I am a shareholder. In fact, I am the single largest shareholder of ATP Oil and Gas Corporation. I am not happy with the performance of our shares on Wall Street. As president of ATP and founder of the company in 1991 I am a builder and am proud of being able to create meaningful value for shareholders. On February 21, 2008 we reported our independent third party year end 2007 total proved plus probable reserves, in other words the expected recoverable as I said a moment ago with pre-tax PV10 value of $5.3 billion and proved reserves alone of $3.5 billion. If you do the enterprise value math of adding our market cap and our debt, subtracting it from our PV10 value and dividing it by the number of shares outstanding, our shares on the expected case have a value greater than $100 per share. In addition, absolutely no value in the $5.3 billion reserves number is given to our floating production systems or to the canyon express pipelines system which I believe has a substantial value since it is the closets transportation system to a number of currently ongoing exploration efforts including the recently announced discoveries by Shell and Exxon in the Gulf of Mexico and Block Mississippi Canyon 393, Desoto Canyon Blocks 353 and 397 of potentially 500 million barrels gross recoverable reserves. So the value we have created is potentially three to five times greater than what Wall Street is giving us.
It is not easy running a company with all of the volatility of price changes, service sector increases, financial community impact, timing of development issues, staffing and personnel challenges, mechanical problems, tax and accounting machinations, vendor performance or lack of it and I haven’t even gotten to what we are all about, oil and natural gas reservoirs. We’ll never perform as you expect. There will also be over or under performance in which case you are dealing with inability to predict expectations.
I am certainly not running a company for my health although I delight in finding creative solutions to retain and motivate the best and brightest people and am soon going to be able to announce to my employees and to the world an imaginative follow up to the Volvo Challenge and the ATP Derby and my ideal will hopefully serve to ensure that our employees remain sufficiently goal orientated and focused to meet an aggressive target. I believe in continuing to make ATP the first choice of high caliper professionals for their oil and gas careers in the US, the UK and the Netherlands. Every function of the E&P industry performed globally by Royal Dutch Shell with its 108,000 employees is performed by ATP internationally with our highly productive 64 employees.
Just what have we created? Well, we have a company that has just delivered again a substantial increase in annual production to a record 10.7 million barrels equivalent. We increased proved reserves which are now 50% oil and 50% natural gas. We increased proved developed reserves. We again had a reserve replacement greater than 200% of our 2007 production, the actual reserve replacement was 223% and we achieved annual revenue of $599.3 million with an annual net income available to common shareholders of $48.6 million. Our Canyon Express pipeline system with 500 million of capacity is on our books at nothing and yet its value is soaring on each announcement of exploration success in its surrounding area.
However, for the exceptional 98% success rate of our development activities, the strength of our reserves and inventory of development projects and all of the record setting production of this company created back in 1991 in my living room, our share price tells me we are not being rewarded. We are trading at our 2005 levels. I am not satisfied, I am not pleased. Wall Street is sending a message when all of the growth of 2006, 2007 and thus far 2008 is being ignored. Fortunately, our assets have very real value and I am determined to see that our shareholders realize that value one way or another. We are obviously dependent on successful execution of our development plans of our rich and deep inventory of projects. At ATP I’ve surrounded myself with outstanding talent who can execute strategic plans and I don’t think anyone is better than Leland Tate our chief of operations who is prepared to give you our operations update.
Leland E. Tate
Good morning everyone. My intention is to abbreviate this portion of the presentation this morning just slightly and provide us all with some more time for questions as we go forward. Year 2007 I believe was another excellent year at ATP, a year where we again, as Paul has mentioned, had record production with significant additions to our reserve base. This morning I’ll briefly report on these areas as well as our progress in the ongoing developments and I’ll relay the fourth quarter results to you.
But before getting to our development program I’d like to point out that we experienced an extraordinary year in 2007 concerning reserve addition. We achieved a 12% overall increase after production is removed and our proved reserves up to 119 million barrels of oil equivalent that’s about 716 BCFE and increased our proved and probable reserves to 182 million barrels of oil equivalent to about 1.09 TCF of reserves. A key point to these additions that I think may be missed is that 74% of the proved reserved additions of 143 BCFE during 2007 came from revisions, extensions and discoveries which I believe is a very, very strong indication of the quality of our current asset base to generate opportunities for us as we go into the future.
For the development activities progress continued very rapidly during 2007 and specifically in the fourth quarter as we completed work at Mississippi Canyon 711, Ship Shoal 351, South Marsh Island 190, Eugene Island 71 and the Telemark Hub here in the Gulf of Mexico and at Wenlock and Tors in the UK. With the completion of this work ATP drilled or sidetracked 11 new wells during 2007, installed two new platforms, completely revamped the subsea system at Gomez and initiated the Telemark MinDOC construction to be completed this year and installed in 2008. The 08 program will focus on these larger projects primarily at the Telemark Hub at Gomez and in the Cheviot area in the UK and it will require somewhere around $700 plus million dollars of capital for year 2008. With the projects that we have in our hands we have a very large future growth potential and that potential will be further augmented by continued future acquisitions which we continue to see becoming available and there is some very good opportunities that we can follow up on.
We’ve produced 20.2 BCFE in the fourth quarter of 2007, as Paul has mentioned and an overall 64 BCFE for the year. This is another record year for us and represents a 26% increase over 2006. As you may have seen we were able to achieve 300 million cubic feet a day equivalent for a short period in late December prior to production issues at our Wenlock field which constitutes about 4% of our proved reserves, Wenlock does. We are presently developing plans to further asses the flow constraints at Wenlock and should implement those during the second quarter. At present we’re producing about 245 million cubic feet a day equivalent and should average between 240 and 250 for the first quarter. I look forward to further reporting to you as the year progresses in these areas. And with that I will turn it over to Al Reese our CFO for the financial comments.
Albert L. Reese, Jr.
You will note that the speaking part of the call will be shorter today. We’ll be going to Q&A much earlier than we normally would. I’m going to not go through what I normally do and that is many of the lines and items and I am prepared to do that in Q&A if they want. I really only have four items to talk about which I think will probably eliminate some questions. One is that fact that you’ll not that our 10K was not filed on Friday, we like many other companies took advantage of the weekend, we did file an extension and we should have the 10K out shortly. Nothing of issue here otherwise we wouldn’t be able to put out a press release so it just gives another set of eyes to look at it one more time to make sure its complete and accurate.
On revenue and production, one of the things I do want to point out is the fact that we are shifting to an oilier company than in the past much of that has to do with our moving in to deep water, primarily Gomez. For example first quarter of 07 38% of our production came from oil, in the fourth quarter of 07 47% of our production came from oil. As Leland pointed out earlier we produced about 245 million per day equivalence thus far this year and about 45% of that is oil. On the revenue side in the first quarter of 07 revenues were 38% from oil, fourth quarter of 07 more than half of our revenues 55% came from oil and every quarter in 07 our oil component increased. We also had a nice increase in realized price this year part of it had to do with our hedging program, part of it had to do with the general uptick in prices both in the Gulf of Mexico, the UK and in oil categories we were up compared to where we were in 2006. As we look forward into 2008 and beyond we don’t have it in the press release but it’s in our most recent presentation I have a nice hedge program we’ve got about $1.2 billion in product hedged over the next several years, most of that in 2008 and in 2009.
Another item that I’ll talk about in the financials is the impairment in the abandonment expense. The impairment came at predominantly two properties in the fourth quarter the first was in our Matia/Cabrito complex Garden Banks 142 and 186, that number was a little more than 15.5 million on Helvellyn over in the UK made up the balance of that. The abandonment that’s just a group of properties, some of that had to do with actual costs incurred a lot of that had to do with future estimates of costs.
The other aspect I want to talk about is evaluation. I want to follow-up on what Paul said, we have created an enormous value here, not only is it in our floating production system Canyon Express but a lot of our producing properties, our developed properties. I will continue to talk about the MLP I don’t think anybody is surprised that we haven’t gotten it done the markets just has not been as receptive, the general credit markets along with MLP markets. The good thing about the MLP market what has gotten hit has been the E&P sector MLP is the infrastructure MLP seem to be doing pretty well. We are still moving forward with an MLP if not an MLP some form of sale lease back, something to monetize these floating production systems, same thing with our producing properties primarily over in the UK. The value that has been created has been tremendous. We can continue to harvest those that production harvest the revenue over time or we can move in and monetize some of that value today put that in the hand of shareholders sooner rather than later and I would expect for us to do that during 2008. And with that said I will give it back to Paul and we can go to Q&A.
T. Paul Bulmahn
We are prepared now to take your questions.
Question-and-Answer Session
Operator
(Operator Instructions) We’ll take our first question from Neal Dingmann with Dahlman Rose.
Neal Dingmann – Dahlman Rose & Co.
I was wondering could you go over a little bit, maybe Leland, as far as current production it sounds like I think you said around 245 versus I think it was the January update where you mentioned you were closer to 260 year-to-date, I was wondering just sort of what’s going on with term production? And then maybe kind of around that if you can give me more color on Wenlock, kind of what the near term plans are around there?
Leland E. Tate
Our accumulative production through the first two months of the year has been a little lower than expected due to some operating issues at Gomez actually. We’ve been trying to re-over haul our compressors and keep them all running properly and so we’ve had a little bit more down time than expected. I think we will be between 240 and 250 for the first quarter, we have been averaging about 250, we’ve seen days as high as 267 or 268. The well performance is still good it’s all a matter of down time. Will we be at 242? Will we be at 235? Will we be at 252? I don’t know but my estimates are its somewhere between that 240 and 250 range. Everything seems to be clicking along pretty well. We have our normal ongoing issues with operations, it seems like it’s something every day and that’s the nature of what we do.
Wenlock I’d like to spend a little bit more time on with you though because I think the reaction to our original reports, to me is a little bit harsh. Wenlock, as I have said before on this call actually was my favorite of the projects in the UK and it does have some issues which I don’t understand right now and I’d like to explain a little bit of that. First of all there’s about, to set Wenlock in perspective it represents about 4% of our reserve so it’s important in a net asset value in a V-perspective but in a scheme of things it’s not the critical issue that we have in the company. What it is, is it’s affected our near term cash flow in that we, I, fully expected to be producing 60 million a day, 50 to 60 million a day, from that well on an average for 2008 and the reality is shortly after we were able to see several days of 300 million a day, a few days after that, a week after that, it became obvious something was awry with the well. Now backing up even further they’re about somewhere in the range of 70 to 100 BCF of gas in place at Wenlock within the structure, well defined.
We have two wells that were originally drilled there, one up dip, one down dip, they were tested, it’s a layered system, which means there are five different layers that produce gas and so we have a well defined system that we used best technology to develop. What that means is we drilled a horizontal well 3,950 feet long between these two wells that were drilled earlier. The up dip well produced at 74 million cubic feet a day, the down dip well produced at 25 million cubic feet a day. We have pressures, samples, we have the reservoir well defined. The issue is we have a well now that is under performing from a rate perspective. The reserves are still there, they haven’t gone away, they’re still there and the rate issue that we’re dealing with is one that we only have surface boil pressure and rates to try to evaluate what’s going on. In the second quarter we built a program to go in and actually re-enter the well with wire line to define which intervals are actually contributing and which ones aren’t.
I could build a myriad of outcomes here, all the way from there’s an obstruction in the well bore to near well bore damage as a result of drilling, to the fact that we were basically vertical through the upper zone and we just got into a tighter permeability area in the upper zones and it’s the lower horizontal portion of the well and the good rock, the really good rock, that’s been producing the high volume and in fact if we decline off, we’ll reach a point at some rate where all these reserves will get produced out of the existing well, to the worst of the worlds is that we’re in a small fault block and we have to get out of that fault block in order to access the entirety of the gas. I find that extremely difficult to believe in that we drilled almost a mile long section and statistically I doubt that we are in that small fault block. All that’s to say the reserves are still there, the rate’s disappointing. We’re trying to figure out what’s going on and it’s possible that we’ll be able to either remove a plug, stimulate a damaged reservoir or in the case of accessing the entire rock we may have to drill a second well to actually access that entire gas in place volume of 70 to 100 BCF. All in all it’s still a very good project and I think one that we’ll recover the original reserves that we thought we would, it’s going to take some time and work and we’ll have to better define what’s going on before we’ll know exactly what to do.
Neal Dingmann – Dahlman Rose & Co.
It’s tough to say on the timing behind that then, Leland?
Leland E. Tate
Yeah, it’s still winter in the North Sea and actually getting out there is not as easy as you might think. It’s not like the Gulf of Mexico. It’s an unmanned platform which means that you have to work off boats and actually get on top of the platform to do the work with wire line. It’s somewhere late April or early May before we can actually access the platform given the weather patterns that we’re seeing and so it’ll be then when we actually can determine down hole information that will better help us describe what’s going on.
Neal Dingmann – Dahlman Rose & Co.
And then let me ask a little bit more, your time with the wire line behind Wenlock, what I – and I think Paul even had suggested to the bottle cost of the services out there, what are you seeing as far as rig service costs, Leland, as far as availability there, both in the UK and the Gulf and what are you seeing most recently in pricing?
Leland E. Tate
On drilling rigs prices have stabilized to some degree, they’re actually continuing to go up just a little. When we finished the K3 well we had the opportunity to take the rig again and it was for a price that was about 5 to 7% higher than we had it. In the North Sea prices generally don’t go up and down rapidly. They sort of stabilize that market by moving in and out with mobile rigs so they basically hold the market reasonably constant. It’s a high priced market. We’ve always known that the North Sea was a high priced environment but the market seems to be stabilized. Availability, I believe that if we wanted a rig we’d be able to get one, sometime late this year, early next year, depending on what we decide we ultimately need to do.
Neal Dingmann – Dahlman Rose & Co.
Last for you as far as infrastructure needs the rest of this year, is it safe to say it won’t be as high last year?
Leland E. Tate
Infrastructure in the UK?
Neal Dingmann – Dahlman Rose & Co.
Yes, sir.
Leland E. Tate
Our program in the UK is one of primarily, if we don’t reenter the Wenlock well evaluating the production that we have there and starting the project at Cheviot later on in the year. So our capital program in the UK this year is primarily focused on Cheviot.
Neal Dingmann – Dahlman Rose & Co.
And then one very last question I could ask Al, as far as around the hedging, are you fine where you are now, Al, and what do you all see for maybe the remainder of the year, both UK and overall?
Albert L. Reese, Jr.
From the volume hedge standpoint, we’re fine. I do get to report that we put in place a $100 hedge earlier in February, I should say late February, but a couple weeks ago, [inaudible] March and April. It’s nice to have some triple digit hedges on the books. As we bring on more production you’ll begin to see us take more and more hedges.
Operator
Our next question from Sven Del Pozo from CK Cooper.
Sven Del Pozo - CK Cooper & Company
Would you be able to tell us what Wenlock is producing now, are you at 100% working interest?
Leland E. Tate
Yes, it’s making 25 million cubic feet per day.
Sven Del Pozo - CK Cooper & Company
As far as unit costs are concerned in the fourth quarter, fourth quarter actuals for DD&A and also for lease operating expenses, I’m wondering if – you did mention some operational challenges at Gomez and I was wondering if those had also factored into the fourth quarter 08? I’m just wondering to try to get some feeling behind the trend of the unit cost in the fourth quarter and how that might tie back to actual operational challenges you might have had in the fourth quarter and if those continued into the first quarter? I’m not sure, I’m just asking you guys.
Leland E. Tate
On operating costs, we show I think $1.43 an NCFE in the US and that’s roughly where we were last year. What’s going on there in the fourth quarter, Gomez actually was about, if I remember right, it runs at about $0.87 or $0.88 so Gomez is certainly doing its part to carry some of those higher cost properties. Our shelf properties, the older ones that are low rate tend to be a bit higher. They may be $1.50 or $1.60 because your rates are low and the costs are reasonably fixed. What’s driven our costs from what I thought we should be at, $1.15 to $1.20 is on Canyon Express. What we’re doing at Canyon Express is we’re producing our [Ockenhogwa] field and that field produces water. In order to produce water through a 62-mile pipeline system it requires a lot of methanol and methanol is very expensive. We actually have a cost of about $4.34 per NCFE on [Ockenhogwa], that actually drives your overall costs about $0.25 an NCFE so that $1.43 becomes say $1.18 if you just took [Ockenhogwa] out. The key point with that though is we made $3.5 million on [Ockenhogwa] in the fourth quarter even with that high operating cost and we plan to continue producing it as long as we can make $1 million a month. So our operating costs will look a little out of line but it’s primarily driven by that one high cost operation.
Sven Del Pozo - CK Cooper & Company
So as production is tied in from your Canyon Express field that unit cost will also be expected to decline.
Leland E. Tate
Absolutely. In fact, if we were producing dry gas you would expect that unit cost to be, I’ll pick a number for you, it’ll be $0.50 to $0.75 an NCFE. We basically pay a fixed platform cost which is pretty small and then we pay a processing and transportation tariff. Those all together won’t add up to a whole lot of money. If you’re putting $200 million a day down that pipeline we’ll have a very, very low operating cost. It’s the water and the treatment of that water – we’re trying to get the last bit of gas out of a couple of fields and in order to do that you have to handle the water. Still makes a good profit, it’s just high cost.
Sven Del Pozo - CK Cooper & Company
And while we’re on Canyon Express, would you be able to tell me a little bit about those discoveries that Mr. Bulmahn mentioned from by Shell and Exxon? What are their transportation options, or are you guys the only game in town?
Leland E. Tate
I’m sure they have multiple options and the primary one is to build their own pipeline system. Until they better define the size and overall capability of the field, and it’s hard to say. What we can say is that we have two 62 mile pipelines that are within just a few miles of their discovery. Our pipeline systems are not at capacity and certainly will not be by the time they get ready to develop. We know that to rebuild these pipelines would cost more than $200 million, maybe more than $250 million. So we believe that we can provide a solution to the discovery that’s out there. We don’t know very much about the discovery other than Shell called it a significant discovery and to me that says that they’ve got some pretty good reserves behind that announcement. So we think we have a solution for people, we think that we have the capacity to bring people through and we also hope to be able to get with them when they actually start their development plans to take some advantage of that.
Sven Del Pozo - CK Cooper & Company
You did go into Wenlock in good detail but I was just wondering, I didn’t see any negative revisions associated with Wenlock and the reserve reconciliation which was generally an encouraging report. I’m assuming the reservoir engineers are doing very detailed analysis, I guess they didn’t have enough information at the time in order to negatively revise the reserves? I’m just wondering if you could explain to me how the integrity of the field in terms of volumes at least the reserve estimate seems to be similar just by the slight under performance that we’re seeing there.
Leland E. Tate
Most of the information that we’ve gathered, we’ve given them everything, we gave them all the information right up through the end of the year and their reserve determinations are basically based on that and as a result don’t reflect the poor production from Wenlock. That said, though, I’m not ready to say there will be any negative reserve revisions. We’ve always said our expected reserves here are 50 BCF, crude reserves are 30. And the reason I say that, and I think when we get enough information to bring them back in and show them, we’ll be able to demonstrate as I said earlier, the gas is still there, it may take a bit more capital to get the gas out, but if we can demonstrate that 2e know that the gas is still there and we’re in a damaged area of some sort the reserves may actually go up not down. It’s too early to judge the outcome of Wenlock at this point and that’s not to say that there may not be negative reserve revisions when we actually get all the information. But it’s too early to tell.
Operator
Our next question will come from Leo Mariani with RBC.
Leo P. Mariani – RBC Capital Markets
I wanted to see if we could get a quick update on Tors, what the production is now and the K3 well is doing.
Leland E. Tate
Tors is doing well. K3 is producing about 17 million cubic feet a day. Tors overall is producing around 50 million cubic feet a day. The K2, K1 wells are at low pressure and with this high pressure K3 well in there, they’re a bit limited. What we’re about to do is to drop those wells into compression and actually be able to get the rates up on K2 and K1 and Garrow and we would hope to be able to get that up to around 70 million a day at the time.
Leo P. Mariani – RBC Capital Markets
Any sense on the timing of that project there?
Leland E. Tate
I was at a meeting last week speaking to some investors and I used the word imminent and the fellow looked me in the eye and said, things are always imminent. It’s the winter in the North Sea and this goes through a third-party platform operated by another operator. They have a lot of their own problems they’re dealing with. For instance, at Tors they have dry gas seals problems on their compressors. We’re reluctant to put our wells into compression until they get their compressor problems solved because if we put them into compression and then the compressors are down all the time, we make nothing. So I will still use the word imminent. I believe that we’re 30 days away from having both Tors and Wenlock in compression but it’s the winter in the North Sea.
Leo P. Mariani – RBC Capital Markets
And just to clarify on those production numbers you gave on Tors here, is all that gross?
Leland E. Tate
Those are gross numbers, yes.
Leo P. Mariani – RBC Capital Markets
Switching gears and just jumping over to sort of the drilling side and kind of development side of things, what are we looking at in terms of an 08 drilling program? Just trying to get a sense, I know you had some mention of I think drilling Gladden at some point there, I think its new field operated, I think you talked about it last quarter. Just wanted to see what was going on there and just any other thing that you think is on the drilling schedule in 08.
Leland E. Tate
The drilling plans are firming up, let’s use that word. We completed the South Marsh Island 190 well in fourth quarter and we’ll be bringing it on production when we get the pipeline laid sometime during the second quarter. So that’s one of the new wells that will come on. We are drilling at High Island 589 at this point on the first well there. We took a kick here about seven or eight days ago and got stuck drill pipe and had to back up and start over again. It was a gas kick so we know what the pressure is and we know what the product is. So that well is probably a second quarter production well. We have a couple of other small projects in the making, on the shelf, I’m working shelf first. Our [Wescam] 462 project is one that we will probably do during the second quarter and then we have a well to drill at Ship Shoal 240 which is probably in the third quarter. It’s a single well drilled to an oil project and so it’ll be a third quarter kind of development. It has no infrastructure associated with it as do not the other ones that I’ve mentioned already. So those are the shelf drilling programs.
We will probably commence drilling at Telemark late in the year. In fact, we may actually do some early drilling this summer to drill some of the very shallow portion of the hole to get past some shallow water flow issues that we are wanting to get behind pipe before we move the MinDOC in, then we’ll start the drilling program at Telemark later in the year. The other wells that are ongoing are around the Gomez area, we have one more development well programmed. It’ll either be very late this year or early next year, we’re trying to decide where it will go. It’s a PUD and one that we’d like to get to, but being at capacity at Gomez we’ll slip it as long as we have capacity. The other two wells that are ongoing now in the Gomez area are at Gladden, that’s Mississippi Canyon 800 and at Mississippi Canyon 754, that’s Anduin. Both of those wells have sputted now and we’re in that dry hole portion of the wells and there’s a bit of time to go before we have an answer on that result. That’s by in large most of the drilling program for this year. The major piece of our monies this year are spent at Telemark, where we will spend, as I recall, it’s somewhere around 75% of our expenditures, at Cheviot in the UK getting started on the hull for the first development there and the rest of it is around Gomez where we’ll spend 10% or so of our capital and then the shelf properties are 5, 6, 7%.
Operator
Next we’ll go to Ron Mills with Johnson Rice.
Ronald Mills – Johnson Rice & Company
Al or Leland, I don’t know who is best to answer this, can you walk through the 245 million a day by area? I think in mid January Gomez was plus or minus 150 million a day, the other shelf was about 50 million a day and then you had the North Sea producing the difference. Can you walk through the current 245 million a day by area?
Leland E. Tate
I can. I’m trying to get a file open here to make sure I don’t make a mistake. Gomez out of that is somewhere on the order of net, now we’re talking about net production of 117 million cubic feet of that so it’s a major piece of our US production. The North Sea out of that will be – so our US production in that is about 180 million a day, so 117 out of 180 comes from Gomez. Net UK ranges from 60 to 65 million a day and then the other things in the US that are of substance of course are things like Ladybug produces 11, 12 million cubic feet a day equivalent. The [Ockenhogwa] field produces about 10 million a day equivalent. Our Ship Shoal 351, 358 complex produces about 13 million a day equivalent and the rest of the production that I haven’t added up to get to that 180 is made up of the remainder of our smaller properties.
Ronald Mills – Johnson Rice & Company
In the UK, what’s the split between Wenlock and Tors because I know you have at least at Wenlock until the first 3Bs are produced you only have a 50% interest which goes to 100%.
Leland E. Tate
Yeah. The Wenlock production is about 25 million a day of that.
Ronald Mills – Johnson Rice & Company
Is that net to you?
Leland E. Tate
Yeah, that’s net. Tors is primarily the remainder. Helvellyn is producing, it’s at the end of its cycle, it produces a couple of million a day gross right now because we’ve been producing it hard all winter and we’ll be shutting it in here in April in order to allow it to build up for its next cycle. So, most of the remainder is coming out of Tors.
Ronald Mills – Johnson Rice & Company
Okay. Regarding Wenlock with the 3 BCFE production hurdle, what’s the timing you think you’ll get the 3 BCFE produced so you’re production there will, at least your next production should increase?
Leland E. Tate
We’ve passed that. We passed that in the middle of February, somewhere there abouts.
Ronald Mills – Johnson Rice & Company
So you’re now at 100% there?
Leland E. Tate
That’s correct.
Ronald Mills – Johnson Rice & Company
Okay. Then one last thing on Wenlock, from the production when it came on at 60 million a day, when it was down to about 40 million a day in January to 25 million a day, is that decline continuing? Or, was there something that happen in the past month to go from the 40 million a day level to 25 million?
Leland E. Tate
It’s been a reasonably stable decline but flatting slightly. We expect, as we get to a little bit lower rate than where we are now, to see – one of the options for what’s wrong with the productivity of the well is that should flatten out and you should have a long plateau at that lower rate. We expect to be able to see that flatten out because we think that alternative has the highest chance for what the problem is with the well. So, I don’t know if that’s going to be 15 or 20 million a day but its somewhere below where we are now because we’re still seeing decline on the well.
Ronald Mills – Johnson Rice & Company
Okay. Then, if you look at your Gomez production, I think when we had last spoken that Gomez you expected to remain fairly flat throughout the year and then some of your other Gulf of Mexico developments should mostly offset some of the natural declines out there. So, until you see Telemark come on are you expecting production to remain fairly flat or even maybe show some declines as we move throughout the year?
Albert L. Reese, Jr.
This isn’t guidance. Ron, I’ve been bitten several times on trying to be as accurate as I can with the production rates. With the number of high impact projects that we have going, the numbers are as you can imagine not easy to try to do. I think we will see some continued decline as the year goes on. I don’t think it’s going to be substantial and I’m talking about in a total sense, as we add these new properties they’re going to help prop up the decline. Gomez continues to perform, we’re having operational surface operation problems but that doesn’t – that’s not talking about the reservoir, it continues to perform reasonably well. We have not hit – we’re still on plateau, let’s say it that way, we’re still able to produce what the facility can get through it and I believe we will be for some time to come. So, directly to answer your question I think you’ll see some decline maybe first and second quarters are not too far apart, some decline starting in the third and fourth quarters as we start to see Gomez starting to fall off plateau slightly. I could be wrong, it could be that Gomez just hangs in there for the whole year. It could be that these wells that we’re working on actually add more volume than I think. On the other hand, you know what can go wrong. I mean, you’ve seen us work that. Where we are plus or minus 20 to 30 million a day is not an unreasonable range for the year realizing, I believe we’ll decline some for the year so you’ve got to take us down a little bit in the last half of the year.
Leland E. Tate
Ron and others, one thing you will see us do at all the conferences that we go to this year and all the presentations, we will put out year-to-date production, we’ll try to have how much of that is oil, how much of that is gas. That way we will keep the entire market updated as to where we are almost at any given time both on a quarterly basis and a year-to-date basis.
Ronald Mills – Johnson Rice & Company
Okay. Two more real quick ones, one is for you Al. In the UK you have about 75 million a day hedge I think in the first quarter?
Albert L. Reese, Jr.
I think that’s right Ron. I believe it was around 80 in the first two months and 70 in March dropping down to 55 during the summer and then going slightly back up to maybe 60 million a day, 40 in September and 60 for November and December, something like that.
Ronald Mills – Johnson Rice & Company
And given your current production of 60 to 65 million a day over there, what are the ramifications for you Al on the hedge at 940 versus the higher hedge level at 76 million a day hedge versus your current production level.
Leland E. Tate
Our hedges are in two forms. We have a fixed form of hedge that is we provide volume for a price and then we have a financial hedge where we settle at the end of each month. We’re capable of supplying the fixed volume. The financial hedge has been settling out and there have been some ups and downs in that volume. So, I think with the addition of compression at the two fields, we’ll be able to sustain and get above the hedge volume certainly for March and the 55 million a day summer I don’t think we have any problem at all with.
Operator
Our next question will come from David Snow with Energy Equities.
David Snow – Energy Equities
Could you walk us through Cheviot yet? When you expect and how much production and what’s yours and what capital outlays by year?
T. Paul Bulmahn
Well, that will take the rest of the day.
Leland E. Tate
I can’t be quite that specific but I can get you down the way a bit. Cheviot is project that we have been moving the field development plan forward on. We will be submitting that to the Department of Trade & Industry in the UK during March. It will take them several months to get through the process. We have already spoken to them and they know exactly what’s coming and there aren’t any issues other than the details of the program which will get worked over time. I would anticipate a full approval of our development plan third quarter, somewhere along there and that doesn’t hold up what we’re trying to do. We are embarking upon a program to start the hull construction this year. We will start the topside construction early next year and we will, under our current timing, install that in 2010. The rig will actually start its drilling program probably in the fourth quarter like at Telemark so we’ll be able to get some drilling done, probably not very much production in oil in 2010 and then 2011 starts the ramp upon a well by well basis where we actually get up to a capacity of about 25,000 barrels a day. The pipeline has a 25,000 barrel a day capacity; we think the wells can get there and about 50 million cubic feet of gas sales. So, we’re looking at that whole project, trying to get it forward, get it through the regulatory process. This year we’ll spend a small portion of the overall capital on the project and that will be in the $60 to $80 million range and then it ramps up in 9, 10 and 11 as we continue to drill wells.
David Snow – Energy Equities
Any exploratory wells going to happen in those time periods?
Leland E. Tate
We’re continuing to work the area right around the field there. It would be to our advantage if we pre-drill some of those wells to try to get someone farmed in to testing a couple of exploration concepts that we have there and we’re hoping that we can convince others that those are good concepts. I don’t think we will drill those wells but I think we can get others to drill them.
David Snow – Energy Equities
And what kind of reserves do you think you’ll end up with from your production?
Leland E. Tate
Cheviot has P2 reserves, expected reserves, third party reserves of just over 22 million barrels and around, if I recall, about 100 BCF of gas, maybe a little less than that. Our simulation, we can see a lot of upside to that. We’re more optimistic than the third parties though their outcome is a reasonable outcome. I feel good about the 22 million barrels and 90 BCF of gas and I think there’s upside to that as we go into the development, we’ll have a surface facility there that can have multiple wells on it. We’ll be able to drill wells, redirect wells and I think we’ll be able to get the reserves up above the P2 pace.
David Snow – Energy Equities
Any 3P?
Leland E. Tate
3P there is about, if I recall, about 32 million barrels and just over 10 BCF of gas.
Operator
Our next question will go to Steve Berman with Pritchard Capital Partners.
Stephen Berman – Pritchard Capital Partners, LLC
Al, if I totally ignore the non-recurring stuff in the fourth quarter, just look at production times realized price and all the field level operating expenses [inaudible] and DD&A, G&A and interest expense, etcetera and put a normal tax rate on it of 34% I get a number around $0.89 a share and taking that as a given for a second, the big miss there if you will was the DD&A expense being much higher than expected which I am seeing in a lot of companies that have been reporting lately. So, just your thoughts on that including DD&A now at a new higher level going forward?
Albert L. Reese, Jr.
The quick answer is yes, DD&A is higher and that’s not only for us that’s for essentially everybody out there, it just costs a lot more. Clearly, one of the issues we had on our DD&A was in the UK sector where these numbers were higher than we anticipated, a little over $6 in DD&A in the fourth quarter, about $5 for the year. I think as those numbers, right now, until we finish figuring out Wenlock until we get tours on compression, I think those are probably good numbers to use going forward. On the tax rate, yeah you’re probably good on the tax rate. I confirmed this morning before the call. As it relates to taxes, we will probably not be a cash tax payer in the United States or the UK during 2008 other than we may have a AMT tax that grabs us in the United States to some level. We will probably be a tax payer over in the Netherlands, a cash tax payer in the Netherlands during 2008.
Stephen Berman – Pritchard Capital Partners, LLC
The $240 to $250 million for Q1, I don’t know if you said what you thought the oil/gas mix of that might be?
Albert L. Reese, Jr.
Yes, it was 45%. Year-to-date we are 45% oil and I’ll let you do the math. UK has been probably 60ish million a day for year-to-date. Do you have a year-to-date on the UK?
Leland E. Tate
No, I don’t have one Al but the 45% though is, I think that’s on the total.
Operator
Next we’ll go to Phil McPherson with Global Hunter Securities.
Phil McPherson – Global Hunter Securities
A couple of things, a lot of questions have been answered Al, do you have a hard number for 08 G&A?
Albert L. Reese, Jr.
For 08 G&A it’s probably, a hard number no, should it be somewhere north of where we were in 07, I think the answer is yes. We were a little over $32 million in 06/07. We’ll be above that in 08. It shouldn’t be substantially above that but something slightly above it.
Phil McPherson – Global Hunter Securities
On a formal cap ex basis, you haven’t given us a hard number, are you willing to do that?
Leland E. Tate
We’re still moving projects around in there. I could see how the hit could go up. I mean, explorations success will cause the number to go up and we have two wells going on now. So, it’s hard to give you a hard and fast number that’s why I said $700 plus. I think it could be more than that if we have a lot of success. High Island 589 we may choose to drill another well there, we’ll drill a tail on that well that we think has extraordinarily good exploration opportunity and if so, it requires – it doesn’t require, we’d sure like to drill another well. So, it’s hard to give you a firm number. I think that $700 plus is a very reasonable starting place. It could go up $50 to $75 million with everything happening right.
Albert L. Reese, Jr.
Phil, from the other standpoint what will bring that number down, as I said earlier, we are very, very committed and you can underline that to monetizing some of these assets that we’ve created during the year whether it is through the MLP type program where we actually recoup cap ex that we’ve spent, whether it’s through bringing partners in for some of the development costs. I think you will see our cap ex number change more than once during the year simply because of a evaluation transaction that has occurred.
Phil McPherson – Global Hunter Securities
And speaking on the MLP, it kind of relates to it on the Canyon Express and the Telemark project, what is the capacity of the Canyon Express Leland? You mentioned what it would cost to rebuild but do you have any idea what the full capacity of it is?
Leland E. Tate
Yes. There are two 12 inch pipelines there and they have – the previous at peak they produced about 500 million cubic feet a day through those pipelines. So, roughly 250 million per pipeline. It’s really a nicely designed system, you can segregate the two pipelines and you can put, if you really wanted to, oil down one and gas down the other, it has a lot of flexibility. Right now it’s just designed as a parallel gas flow system and primarily because the Myacine out there has been mostly gas but as people start to drill deeper in the basin and start to pick up some oil that may change.
Phil McPherson – Global Hunter Securities
Can you give me the capacity at Telemark too? What the MinDOC good capacity is going to be?
Leland E. Tate
The MinDOC capacity, we will have in excess of 100 million a day through that system expandable to almost 200 million. The oil system has about 35,000 barrels a day, we believe we can get that up to 40 if we really chose. So, we’ve got lots of capacity out there. Al mentioned the whole of our Sub C assets, one of the projects that we have ongoing is to look at how we can monetize that pipeline system because it does go about 60 miles out into deep water right at the mouth of the Mississippi Canyon so there’s not that much infrastructure in there and we think it has quite a lot of value.
Phil McPherson – Global Hunter Securities
You’re talking about the Canyon Express pipeline?
Leland E. Tate
I’m talking about Mississippi Canyon, the Telemark pipeline.
Phil McPherson – Global Hunter Securities
Okay. Mississippi Canyon pipeline, I got you. One question I had on the Telemark or on the MinDOC system as a whole, can you give us an example of other areas that the MinDOC is being used? When you talk about the MLP and this having a 30 year asset life, let’s say five, six years from now you’re done with Telemark, is this a type of floating production platform that can be used on some of these bigger discoveries in Brazil that we’re hearing about, or things in Western Africa? Can you give us some color on that kind of flavor?
Leland E. Tate
First of all, it is portable. It’s a spar, you’ve heard us use the word spar in the past, it is a spar, its just got three legs instead of one. It’s a new design, three columns and is portable. We’ll be able to, once it’s finished where it is, remove the mooring and take it to a new location. The opportunity set for it is fields that you want to produce somewhere – first of all you have surface well heads also, fields with multiple pay reservoirs that are in the 40 to 60 million, 70 million barrel range because you don’t want your plateau to be too long where you can produce three of four wells in multiple intervals that you have to reenter and change zones in. It’s ideal for that kind of a concept. If you’re talking about a 300 million barrel oil field, it’s not designed for that because your plateau would be too long at 35,000 barrels a day. That’s not to say you couldn’t change the topside facilities and increase the capacity but I’m referring to it as it is in its current state so it’s designed for that field that needs that 25, 30,000 a day oil capacity plateau and 50 to 100 million cubic feet a day capacity plateau which is going to put you in that – the ideal size is about 50 to 100 million barrel field.
Operator
Next we’ll go to Richard Tullis with Capital One.
Richard Tullis – Capital One
I think most of my questions have been answered already I just want to touch on one or two more things. Leland, the wells being drilled now [South Marsha Island] and [Highland] what do you expect in a range of net production from those later this year?
Leland E. Tate
At South Marsha Island we believe it will bring another well on at 6 to 8 million cubic feet a day of gas and it has about 100 barrels per million of condensate with it so it will make about 6 million and 600 barrels a day of condensate – would be 800 barrels of condensate. It’s a very rich gas so you’re getting lots of value out of the condensate on that field. So let’s say 6 to 8 million a day and 600 to 800 barrels a day of condensate. High Island is a bit more difficult to describe to you. The logged hydrocarbons that we’re drilling actually are more gas than liquid, we think. They will have some yield to them 20 to 30 barrels per million is what we anticipate. Those wells should be able to produce in the 10 to 12 million cubic feet a day range so that will give you a field for the gas zones there. The exploration tail that we’re drilling, we anticipate it to be oil and actually have installed well facilities on our platform. The offset wells have made significant oil, 2 to 3,000 barrels a day in some cases. So, right now it’s exploration and we can’t give you an answer on that.
Richard Tullis – Capital One
Going back to Gomez what do you kind of expect from Gomez in the second half of this year production wise?
Leland E. Tate
I tried to put some color on that earlier; it’s really difficult. The wells are performing so that they’re still on plateau. I think they’re going to be on plateau for some period of time. In the third quarter if they start to decline I think you will see probably a 10 to 15% decline per quarter, something like that. That would probably be a high decline rate if in fact we can get gas lift going and keep the wells flowing nicely even though they’re making water which is what’s going to happen here eventually. Then, we might be able to hang in there and keep that plateau a little bit longer or else at least reduce the decline.
Operator
For our next question we’ll go to Joan Lappin, Gramercy Capital.
Joan E. Lappin – Gramercy Capital Management Corp.
You mentioned in your opening remarks that you feel that you’re stock is quite undervalued, I don’t disagree and that you would take whatever steps are necessary to realize that value. I wondered if you would enumerate what you consider those options to be.
T. Paul Bulmahn
I will close with those comments.
Joan E. Lappin – Gramercy Capital Management Corp.
Okay. I’ll wait until you do.
Operator
For our next question we’ll go to Rehan Rashid with FBR.
Rehan Rashid – Friedman, Billings, Ramsey & Co.
Just a little quick update on the MinDOC both one and two, how far are we on construction? And, is everything on schedule?
Leland E. Tate
MinDOC one is about 60 to 65% along. The hull obviously, is further along than the topside but both are progressing well. It hasn’t been easy. We’ve dealt with labor issues trying to make sure we had enough people doing welding, we’ve dealt with technical issues but we worked our way through all of those. We anticipate that we’ll be able to take the hull out of the dry dock in late August and upright it as I said during September, install the topsides on it in October and the window that we’ve been given by the heavy lift people and put the rig on it shortly after that and hopefully commence the drilling program before the end of the year. MinDOC two we’re moving forward on, we’ve bought steal, we’re looking at – its schedule is driven by the first one. It may be delayed a bit because we’re still in the dry dock so we need to really work our way entirely through that piece before we can give you a real good schedule on it. We have moved forward with it though and it should be easier this time than it was the first time. Some of the things that we found that engineers think you can do and construction people are not sure, we’ve worked our way through so it should be lower cost and actually a little faster than the first one was. But, we do have to get everything lined up from a construction planning perspective.
Rehan Rashid – Friedman, Billings, Ramsey & Co.
Okay. That’s good. Going back to Wenlock real quickly, how has flowing cubic pressure moved with production movement? Is that kind of telling you anything on the down hull conditions that could help us think through it as well?
Leland E. Tate
The pressure obviously was the first thing we saw declining as it started to drop the down hull pressure you saw cubic pressure falling also. We were able to maintain capacity for some time before we actually saw gas rate and pressure declining. We’ve actually moved down to the high pressure separator rate over at the platform now with our pressure at the Wenlock platform and that’s why as quickly as we can add compression we’ll be able to get the rate back up again because we have another I guess it’s almost another 1,000 pounds of pressure that we’ll be able to drop on the well head, reduce the well head by in order to increase capacity. So, we have seen both well head pressure and rate fall but we look at that with a simulator and actually it takes into consideration the hydraulics and the friction associated with both pressure and rate so that’s what we’re trying to use to figure out exactly what happen.
Operator
At this time we have a follow up question from Ron Mills with Johnson Rice.
Ronald Mills – Johnson Rice & Company
A couple of questions, on the MinDOC two that you talked about you address that well, in terms of what are some of the potential snags left on the first MinDOC other than the potentially weather related once it sails out?
Leland E. Tate
Well, the first thing we have to do of course is moor it and we will be going out this month, late this month to install the anchors and tether on the rope. We’ve had some trouble for instance with the piles, welding in the piles weren’t exactly the way it was supposed to be and we had to rebuild piles. But, that should all be ready to go out though by the time we get to the construction season late this month. That’s one example. Shouldn’t be a problem, we worked our way through it. The other thing that can happen, you float it out and during the uprighting process – probably the biggest risk we have is weather. It is during hurricane season and we’ll have to be especially careful because it will take us about 10 days to get it uprighted. We’ll be very careful about when we actually take it out. So, I would say weather is the biggest risk we have to schedule at this point not only for the installation of the hull, uprighting it and getting it in place but also it takes pretty clam weather for the topsides. That’s only a four or five day effort so it’s not as time sensitive as the hull is.
Ronald Mills – Johnson Rice & Company
Okay. Then Leland, just on the reserves, you talked about the revisions extension discoveries represented a significant amount of your reserves adds plus or minus a 100Bs. Do you know how many of those were pressure related versus performance and discovery related?
Leland E. Tate
Very, very, very little price related reserves. The third party reserve engineers, unless you have a really long tail actually don’t change the reserves very much at all. They’ll often times cut the cash flow off when it’s still slightly positive. It doesn’t change the overall PB10 of the project. It does add a few NCFEs but it’s very little change. I’d say essentially none were price related.
Ronald Mills – Johnson Rice & Company
Then Al, G&A in the fourth quarter do you know how much of your G&A was non-cash?
Albert L. Reese, Jr.
Yes I do. It was approximately $2 million of non-cash in the fourth quarter.
Ronald Mills – Johnson Rice & Company
Is that a pretty good run rate as we look ahead for 08? Or, should we use the $1.5 million run rate that you’ve been running?
Albert L. Reese, Jr.
$2 is good for G&A non-cash run rate for 2008.
Ronald Mills – Johnson Rice & Company
Okay. Then, on the tax rate which Steve mentioned earlier, should we continue to use that 34 to 35% tax rate for you despite what looked like a lower tax rate in the fourth quarter?
Albert L. Reese, Jr.
Yeah, the lower tax rate in the fourth quarter is essentially us finally utilizing all of the deferred tax asset that we have, that’s what brought it down in the fourth quarter. But, going forward you end up with about 50% in the North Sea area, about 34 to 35% in US area and fourth quarter that was essentially our valuation account elimination there. We said we’ve got a little bit left but most of its all gone.
Ronald Mills – Johnson Rice & Company
So then on a combined basis we should really be using the tax rate somewhere closer to 38 or 40%?
Albert L. Reese, Jr.
That would probably be about right.
Operator
There appears to be no further questions at this time. Mr. Bulmahn I’ll turn the conference back over to you for any closing remarks.
T. Paul Bulmahn
Thank you all for your questions. ATP will continue to execute its development strategy as artfully as we are able but the message from Wall Street is loud and clear. We are exceedingly focused on achieving shareholder value. If our share price and market capitalization is not going to change and this is partially in response to Joan Lappin’s earlier question, every possibility of which I am aware including a MLP, sell downs of significant properties, a possible IPO of the North Sea subsidiary, everything is being considered and a number of things are being worked on simultaneously, nothing is off the table.
I thank the entire global ATP team for their efforts in 2007. We appreciate your interest in the company by your participation in this call and we look forward to seeing you in Houston or at the next conference. Thank you.
Operator
That concludes today’s conference. We do appreciate everyone’s participation and have a good day.
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