Anadarko Petroleum Corporation Q4 2008 Earnings Call Transcript

| About: Anadarko Petroleum (APC)

Anadarko Petroleum Corporation (NYSE:APC)

Q4 2008 Earnings Call

February 3, 2009 10:00 am ET

Executives

John Colglazier – Investor Relations

James T. Hackett – Chairman and CEO

Charles A. Meloy - Sr. VP, Worldwide Operations

Robert P. Daniels - Sr. VP, Worldwide Exploration

Karl F. Kurz - COO

Clay Bretches - Vice President of Marketing

Analysts

David Heikkinen - Tudor Pickering & Co. Securities

Benjamin Dell - Sanford C. Bernstein

Ellen Hannan - Weeden & Co.

Brian Singer - Goldman Sachs

Robert Christensen - Buckingham Research Group

Joseph Allman - J.P. Morgan

Thomas L. Gardner - Simmons & Company

John [Wagazino] - Wachovia.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

Stephen Beck - Jefferies & Company

John [Emdine] – Wood Mackenzie

Philip Dodge - Stanford Group

Raymond Deacon - Pritchard Capital

Doug [Leggate] - Howard Weil

Jeb Armstrong - Calyon Securities

Operator

Good day, ladies and gentlemen and welcome to the fourth quarter 2008 Anadarko Petroleum Corporation earnings conference call. My name is Stacy and I’ll be your conference moderator for today. At this time all participants are in a listen only mode. We will be facilitating a question and answer session towards the end of the conference. (Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the presentation over to your host for today’s call, Mr. John Colglazier.

John Colglazier

Thank you. Good morning and thank you for joining us today for Anadarko’s fourth quarter and year end 2008 conference call. Joining me on the call today are Jim Hackett, our Chairman and CEO and other executives who will be available to answer your questions later in the call.

As a reminder, we have posted additional information in our fourth quarter operations report available on our website at www.anadarko.com.

Before I turn the call over to Jim, I do need to remind you this presentation contains our best and most reasonable estimates and information. A number of factors could cause actual results to differ materially from what we discuss. You should read our full disclosure on forward-looking statements and our presentation slides, the latest 10-K, other filings and press releases, for the risk factors associated with our business. In addition, we will reference non-GAAP measures so be sure to see the reconciliations in our earnings release and on our website.

We encourage you to read the cautionary notes to US investors contained in the presentation slides for this call, and with that, let me turn the call over to Jim Hackett.

James T. Hackett

Thanks, John. Good morning everybody. As you saw on last night’s release, Anadarko delivered a very good quarter as our asset portfolio showed depth and balance in managing through the challenges we faced in 2008.

Looking ahead I have not been more excited about the quality of exploration and development projects assembled in our portfolio. Even in today’s price environment where we have to carefully shepherd our capital. We are pursuing a wonderful set of appraisal and expiration opportunities as we enter 2009.

Our substantial liquidity also enables us to execute upon this operational program while maintaining a very strong balance sheet. I want to highlight some of the accomplishments detailed in last night’s release.

First, we exceeded investor guidance for organic reserve adds for the year by adding 290 million barrels of oil equivalent of new reserves. I’ll provide more detail on this very positive news later in the call.

Second, we delivered sales volumes towards the high end of guidance at 52 million barrels of oil equivalent for the quarter, overcoming the continuing third party effects of Hurricane Ike, which resulted in approximately 45,000 net barrels per day of Gulf of Mexico production shut ins.

Third, we increased total sales volumes year-over-year by approximately 5% from retained properties, overcoming the deferral of approximately 13 million barrels of production resulting from hurricanes and other third party infrastructure issues over the last three quarters of 2008.

This year-over-year production increase was underpinned by the Rockies region with a 17% increase in sales volumes. The Greater National Buttes area and Powder River Basin were the key drivers with sales volume increases of about 30% and 45% respectively over 2007 levels.

Beyond the revenue generated by production volume growth, our operating teams have done an outstanding job of cost control by striving for continual improvements in our drilling efficiencies. This success is detailed in the operations report and it demonstrates our significant enhancements spud to rig release times, rig mobilization times, and a 12% overall improvement in the amount of time it takes from spud to spud in our core onshore operating development and drilling operations. As a result we’ve been able to maintain our level of activity with fewer rigs and without increasing capital during a year of sizable service cost increases in the industry.

Turning to the expiration side of Anadarko’s business, our global program continues to deliver exceptional results. As announced Monday, we made a substantial deepwater Gulf of Mexico discovery at the Heidelberg prospect in the Green Canyon area. The Heidelberg discovery well encountered more than 200 feet of net oil pay and multiple high quality Miocene sands.

This continued success of our program in the Green Canyon area validates our geologic interpretation of the sub-salt Miocene trend and strengthens our successful track record in the deepwater Gulf of Mexico. Including Heidelberg, we’ve now made seven major discoveries in the sub-salt Miocene trend since 2005, each targeting resources of more than 100 million barrels.

Additionally, Heidelberg’s proximity to our Constitution spar validates the benefit of our hub and spoke system with multiple platforms in the Gulf by allowing us to consider stand alone or tieback options once we conduct further appraisal work, which we expect to begin later this year.

When we wrap up activities in Heidelberg, we expect to move the Amos runner rig despite another minimizing test to the Vito prospect in Mississippi Canyon block 984, which we operate with a 20% working interest.

In addition to finding new resources, we are moving existing discoveries forward as well. During the fourth quarter our Board sanctioned the development of the Caesar/Tonga complex in the Green Canyon area which has an estimated resource range of between 200 million and 400 million barrels of oil equivalent.

We anticipate having our first significant volumes from this development in 2011. We expect to tie Caesar/Tonga production back to our Constitution spar, significantly reducing development costs and time to first production.

Moving from the Middle-Miocene to the lower tertiary we are currently drawing the Shenandoah well located in Walker Ridge block 52. The well is targeting a Wilcox objective and we expect to announce results shortly.

We are also having excellent success in transferring our deepwater skill sets internationally, especially in Ghana.

The [dubois] field is one of the top new discoveries in the world and we’ve had six successes from six wells in this emerging core area, with five successful exploration appraisal wells in the [dubois] field and in other successful exploration well at the nearby [Odum] prospect.

During the fourth quarter we announced results of the [Sedguwood] number two well located three miles to the northwest of the original Mahogany number one discovery well. Recently our partners announced the successful Mahogany number three well located about three miles to the southeast of the discovery well.

With Mahogany number three we’ve also discovered a new oil bearing zone that provides additional opportunities for meaningful resource additions. As a result of these step out wells, the operator recently increased the field’s estimated resources to arrange a 600 million to 1.8 billion barrels of oil equivalent.

In addition we completed a DST at [Sedguwood] number two with strong results. The flow rates were approximately 17,000 barrels per day at 37 degree API gravity crude and the test demonstrated that the well is capable of pulling more than 20,000 barrels per day. The results also confirmed the quality and connectivity of the reservoir.

We are moving forward with the [Bellman] program in Ghana and anticipate four rigs operating in the area by the end of the first quarter. This active drilling program will encompass a combination of appraisal, development, and expiration wells including the Jubilee lookalike prospect at Tweneboa which we recently spud on the deepwater Tano license and the Teak prospect located on the West Cape three points block.

Turning to offshore Brazil, we were the first foreign operator to announce a deepwater pre-salt discovery at Wahoo. Planning is now underway to run a multi zone DST towards the middle of this year and we also anticipate drilling additional appraisal and expiration wells in 2009 on this C-30 block.

Earlier in the year we also discovered hydrocarbon in the circle well on block ES 24 offshore Brazil. However, after returning the rig to serp and reaching the primary objective, it appears the results do not support a commercial standalone development at this time.

However, the data provides valuable information and encouragement for additional exploration on Block 24 and the adjacent block ES 25 where we currently are drilling the Coalho prospect with a 40% working interest. We expect results on this well near the end of the first quarter.

Our US onshore expiration program in the Marcellus, Haynes, and Maverick shale plays continues to deliver positive results. Our first horizontal completion in the Marcellus was a success, testing at approximately 4.5 million cubic feet of natural gas per day. We’re currently completing a second horizontal well and have two others n various stages of drilling.

We expect to continue to act a program in 2009 with additional horizontal and vertical tests in the trend. We’ve provided some additional detail on each of these areas in our Quarterly Operations Report that is available on our website.

In addition to the noteworthy operational accomplishments discussed today and provided in our Ops report, our earnings release provides financial highlights from the quarter and the year. We’ve restored the balance sheet, maintained our investment grade rating, and built a very strong liquidity position.

We also achieved an approximate 34% net to debt cap ratio within the target range we set for our post asset divestiture program over the last two years without issuing equity. We ended 2008 with approximately $2.4 billion of cash on the balance sheets after retiring about $370 million of total debt during the quarter and closing the divestiture of the Peregrino heavy oil field offshore Brazil.

We continue to maintain additional financial flexibility and liquidity through our undrawn $1.3 billion committed revolving credit facility which does not mature until 2013.

Before we turn the call over for your questions I want to walk you through the results for our reserve additions for the year. As stated earlier, we added 290 million barrels of oil equivalent approved reserves before the effects of price revisions which calculates to replacing over 140% of reported sales volumes for the year.

We spent $4.78 billion on oil and gas expiration and development activities. We estimate our prove reserves at year end totaled 2.28 billion barrels of oil equivalent which takes into account approximately 137 million barrels of oil equivalent associated with divestitures.

Price related revisions primarily associated with the year-over-year price declines for crude and NGLs resulted in a 4% decrease in total prove reserves which is low relative the absolute commodity price drops year-over-year and reflects very positively on the economic quality of our asset portfolio.

Reserve additions were primarily driven by development and install activities in the Rockies and appraisal drilling in the Gulf of Mexico. We’re pleased with the capital efficiency of our portfolio, especially when taking into account that more than 30% of our 2008 capital went to long term projects like Jubilee, Wahoo, and other expiration spending that did not add reserves in 2008.

We talked about this before but with the rapid decline in commodity prices, we want to reiterate that in current service costs, the majority of our core national gas projects onshore in the US are capable of generating at least a 10% incremental rate of return at a NYMEX flat gas price dec of approximately $5.

Also with current service costs and a flat NYMEX price of less than $30 per barrel, our major deepwater projects such as Caesar/Tonga and Ghana are each capable of generating greater than incremental rates of return. We’re actively addressing our service costs and expect to achieve material reductions which will bolster the return on our investments.

The quality of our asset portfolio is evident also in the minimal impairments recorded for the year as the economics of our assets held up under a field by field impairment test analysis. As we’ve discussed previously, part of our risk management strategy includes firm transportation commitments and basis hedges covering approximately 95% of our Rockies production in 2009, about70% in 2010, and about 60% in 2011.

We have no material concentration on counterparty risk from the derivatives supporting our basis management. We’ve lacked in differentials in the majority of our Rockies production with average pricing at Henry Hub less $1.25 this year and Henry Hub left $1.28 in 2010 and $1.07 in 2011. As we stated before, we’re committed to an incremental 450 million cubic feet per day up front transportation to support substantial additional takeaway capacity in the Rockies for 2011 and beyond.

Operationally our portfolio is delivering upon investor guidance even with unusual weather and mechanical disruptions in the Gulf of Mexico last year. We exceeded or met our 2008 targets for production growth, organic reserve ads, debt reduction, and production replacement.

We’ve also delivered significant expiration success with additional prospects identified and major opportunities ahead. We believe we are well-positioned with our current portfolio of assets to manage through various price cycles and continue in delivering value for our shareholders.

Our Board meets next week to review and approve our 2009 capital budget and I look forward to talking with you again next week about the capital program and production guidance. We’ll be sending out a news release this morning with the details of a special conference call to be held on February 11. Because we do not yet have Board approval for our capital program, we can’t discuss spending plans except in a general sense today.

Now we’ll turn it over the operator and open it up for questions.

Question-and-Answer Session

Operator

(Operator Instructions) Your first question comes from David Heikkinen with Tudor, Pickering.

David Heikkinen - Tudor Pickering & Co. Securities

Jim, just thinking the general spending sense. Can you talk in general terms about what you’re thinking going into the Board meeting and call next week for 2009 CapEx and production?

James T. Hackett

Yes, I think at the end of the third quarter we had shared that we were going to be at a number that was kind of at or around what we were spending in 2008. We’ve obviously dialed that down meaningfully and we will be getting back to you with the exact number. The important thing is we still think we will grow reserves and production with that number and keep the balance sheet intact and that’s overcoming a number of different factors that we’re facing here currently which are in some ways good in terms of OPEC cuts in Algeria as well as some of the [frac spread crash] that we had at the end of the year on the NGL side as well as the shut in production that we have in the Gulf of Mexico that continues primarily through the first quarter and Chuck can address that a little later in terms of kind of when that comes on.

We want to make sure that we stay committed to our exploration activities and our mega projects for development that really are going to coming on in price environments that are very different than today’s world, so I think when you put all that together we still feel very good about where we’ll come out with the metrics next week.

David Heikkinen - Tudor Pickering & Co. Securities

If you think about your long term project, kind of minimum commitments for ’09 still about 35% to 40% of I guess maybe $1.5 billion, can you put a dollar amount on long term commitments of what the floor would be for CapEx?

James T. Hackett

I think about 20% of it is going to mega projects. Again I won’t tell you the exact numbers here yet and about 20% expiration.

David Heikkinen - Tudor Pickering & Co. Securities

Then on the pipelines in the Gulf of Mexico, that production that’s shut in, what major lines are you tied into and how does that ramp up through the first quarter?

Charles A. Meloy

We really have two issues that we’re dealing with. The first is at Conger which shales repairing the infrastructure there and that should be online sometime in middle to late February and then both K2 Marco Polo complex and the constitution [Taconda Rogo] complex are tied into [Anticonda] and that should be completed in and around the end of the quarter.

Operator

Your next question comes from Ben Dell with Sanford Bernstein.

Benjamin Dell - Sanford C. Bernstein

I just have two quick questions. One was on Sierra Leone. Do you have an estimate of the sort of pre-dip drill estimate the size of that prospect?

James T. Hackett

Robert P. Daniels

I’d say most of the things we’re looking for in West Africa, the range would start at about $100 million barrels of [glub] from there and really looking towards Jubilee Lake accumulations of the same depositional system and really we’re looking at about the same aerial extent of potential reservoirs, so it could be very substantial but I’d say that everything’s going to have a starting range of about 100 million barrels.

Benjamin Dell - Sanford C. Bernstein

My second question was just on the lower tertiary. There’s been ongoing discussions around what sort of flow rates you need to make that economic. It seems higher than modest prices. People were talking anywhere between 12,000 and 15,000 barrels from the wells to get the well rate economic. Do you have a feel for what sort of flow rates you’d need in these sort of commodity prices?

Robert P. Daniels

In the lower tertiary?

Benjamin Dell - Sanford C. Bernstein

Yes.

Robert P. Daniels

I think that number that you threw out there is probably about as good as anybody’s got at this point. I think that one of the key things you have to look for in the lower tertiary is people are just getting to understand what the reservoir distribution is and the quality of that reservoir and I think what we’re working on is how do we get better reservoir quality in the lower tertiary traps that can therefore deliver the higher flow rates that we would like to see and that’s where most of our efforts are going.

Operator

Your next question comes from Ellen Hannon with Weeden and Company.

Ellen Hannan - Weeden & Co.

I think you’ve addressed most of my questions in terms of the longer term outlook on your CapEx spending. I was going to ask you about the creative tension going on within the company in terms of CapEx on the short term versus long term and balancing that between oil and gas and I guess your comments are suggesting we’ll get a better read on that next week.

The other question I had was a little bit more detailed and that was really you alluded to the [fracs spread crash] I think in the fourth quarter in NGLs and can you talk about what you’re seeing there in terms of your income in the midstream?

James T. Hackett

Karl F. Kurz

Obviously we did see the [fracs spreads crash]. In fact went back and looked a couple months ago, they were negative all through 2009. We have seen a modest recovery in those [fracs spreads] in the last few weeks where we see ethane and propane [fracs spreads] for both our Rockies and Southern regions now positive. They’re not near levels we saw last year but we do expect to be in a recovery mode for the foreseeable future.

John Colglazier

I think the second part of that question, in our GPM margin for the quarter, that’s where most of our product inventory resides so with the massive drop in the product prices quarter to quarter, we also had an inventory write down there, so hopefully that’s a one-time event and go forward from there.

Ellen Hannan - Weeden & Co.

Did you say how much that write down was?

John Colglazier

A combination of the [crush fracs spreads] and the inventory write down are pretty evenly split between each of them, about $30 million plus or minus.

Ellen Hannan - Weeden & Co.

Just one other question for me and again this may be a little early. Do you have an estimate for the development costs for Caesar/Tonga?

Charles A. Meloy

The total cost was about $1.3 billion which we have roughly 33% of.

Operator

Your next question comes from Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs

I think you mentioned 20% of next year’s budget or so is on mega projects and 20% on exploration. If we look at the remaining 60%, how do you think about the right level of onshore activity both when you add things up relative to your cash flow but also to insure the type of regrades and service cost decreases that you’re looking for?

Charles A. Meloy

As Jim mentioned earlier, we’re still a little early in our budget cycle to give you an exact proportion that we’re going to spend onshore and offshore, but clearly we’re focusing on the cash generating assets onshore and trying to get the best out of those that we can and we’re working diligently to reduce the amount of service costs of course that go into each of those investments. As John mentioned earlier, our programs in general have great economics even at the lower prices and those on the margin will do what we need to do to make them work for us including not completing the wells and that type of thing so the split still a little uncertain until we get Board approval but our activities are going to be very focused on accretive NAV type.

James T. Hackett

The other thing is we’ll do things like draw back into the more sweeter spots if you will, some of the better economics, and also put some pressure as Chuck mentioned on the service cost side by managing what we’re doing in each area.

Brian Singer - Goldman Sachs

What kind of service cut decreases are you looking for, I think you gave some return assumptions earlier in terms of needing $5 gas, the current service costs. What type of service cuts are you looking for to ultimately get more aggressive and maybe move back to where your original thoughts were budget wise, maybe a month or two months ago.

Karl F. Kurz

You know as we all do right now we’re living with 2008 service costs in a 2004 commodity price environment and we need those two items to converge with service costs coming down with the current commodity price levels. We’re actively working and negotiating and re-negotiating contracts to make that happen. We expect we could see on order of 20% to 45% type service costs for a lot of our pumping service, emitting service, and we’ll get into a lot more of that next week, but the service costs usually are slow to respond. We’re pretty aggressive right now to get them to respond quite a bit faster than historically.

Operator

Your next question comes from Robert Christenson with Buckingham Research Group.

Robert Christensen - Buckingham Research Group

All my questions have been answered, thanks.

Operator

Your next question comes from Joe Allman with J.P. Morgan.

Joseph Allman - J.P. Morgan

In terms of the onshore US rig count, have you dropped it from the fourth quarter average level and what’s the plan on dropping rigs from here?

James T. Hackett

We’ve dropped it pretty significantly from the fourth quarter average for several reasons already. The first is as you know there’s stipulations in the Rockies particularly where those wells, those rigs can only work during the winter months and as we approach the spring we start dropping those rigs down. Through the fourth quarter we had about 68 on average and we’re running now around 40.

Joseph Allman - J.P. Morgan

Separate topic. K2 seemed to be one of the highlights in operations update. Can you just talk a little bit about K2 and where you’re going from here?

Charles A. Meloy

There’s lots of good news around K2. The build performance has improved considerably over our expectations in the last year or so and if there was any good news, I think that was some of it. We saw that some of the water drive for the aquifer support start to kick in. That’s been a long time in coming but from what we’ve seen it will be very beneficial to our recovery, our oil recovery in the field, so with improved performance, lower oil price environment, and still high service costs, the partnership has shifted its focus to the last capital intensive artificial lift type project that should even further enhance our recovery and our performance just by drawing the wells down further and substantially lower capital investment and outstanding returns.

Joseph Allman - J.P. Morgan

Can you talk about the timing, I guess you’re going to put some pumps down there, can you tell about the timing of that and what kind of production rates you might see and then when you might go to get some of those reserves back?

Charles A. Meloy

It’s a little early to give you a full understanding of the project. We’re working with our partners to pull all that together. This was a deepwater project so you could expect a little time to pass, maybe 2010 or so, before we get really good results, and then as we pull the partnership together and get an agreement on what we need to do, we will give you further details on the project.

Joseph Allman - J.P. Morgan

Just a last thing, on Jubilee, based on the data you have, do you think Jubilee is closer to the 600 million barrels or do you think it’s closer to the 1.8 billion barrels?

James T. Hackett

We wish we could narrow the range down but we’re still drilling wells out there and each one is targeting certain areas that can really help us. I think one that we’ve got going down now is going to be real important to us but I think we’re going to stick with the range right now. The thing that I keep coming back to is we drilled six wells out there and every one of them has been positive. We haven’t had any negative news in any of the wells, including the flow tests, so it’s a very, very significant field and we’re real pleased with what we’re seeing but we just have to do more activity out there and drill more wells.

Operator

Your next question comes from Tom Gardner with Simmons and Company.

Thomas L. Gardner - Simmons & Company

I just had a question here on year end price related revisions. How much of that write down was related to gas processing, ethane rejection, was that a huge component?

John Colglazier

As we go through there, as Jim mentioned in the conference call itself, most of the reserve revisions are related to liquids and a lot of it, you saw where Algeria had some negative price revisions associated with it, I’ll throw another one out there for you for a specific field and then that’s about it, but Salt Creek in the Rockies. If the 60% drop in year to year pricing, some of these become challenged and they come back quickly at the same time.

As for the NGL question, it’s a part of it, but it’s not significant. I think that’s about all we’ll share.

Thomas L. Gardner - Simmons & Company

You’ve got these mega projects coming on, just wanted to get an idea of the improved reserve adds, when they’re likely to flow through specifically Jubilee, Wahoo, and the EOR activity at K2. Can you give us an idea of that’s 2009, 2010 event or beyond?

Charles A. Meloy

The Jubilee field was [sanctioning] probably this year. We should see some booking taking place in Jubilee, Ghana development. With regard to Wahoo, it’s still pretty early in that one and we will be delineating that discovery later this year and probably early next and so that’s likely 2010 and beyond event. K2 as we spoke earlier, the EOR activity at K2 is now diminished significantly and it’s most likely just an improved recovery project with artificial lifts, so those will come on as we increase the flow rates from the wells with either gas lifter or ESPs.

Thomas L. Gardner - Simmons & Company

Chuck, some operators are reporting drilling but delaying completion on some wells. Does Anadarko have any of that going on?

Charles A. Meloy

Yes we do. We’re looking at that very strongly and in fact we’re doing some of it now, just waiting for the service costs to get in line with our revenues.

Thomas L. Gardner - Simmons & Company

Any particular region being affected over another in that regard?

Charles A. Meloy

We’re looking at it across the board and with the realizations in the Rockies, that would be the first place we’d look really hard at doing it, but it’s going to happen across the board, it just depends on the economics of the field.

Thomas L. Gardner - Simmons & Company

On the subject of the Rockies, can you give us an update on the regulatory environment and do you see any potential threats to Anadarko’s gross [story] in the region with any pending regulation, if you will?

Karl F. Kurz

Obviously the regulatory environment could change rapidly up there. We see some issues that make us concerned but right now we are confident that we can execute our 2009 and 2010 programs as designed. As you’ll hear more next week, we’ll be reducing our capital spending in all areas so with that reduction and also the industry reduction in the Rockies, we think the ability to get our permits approved and continue our activity will still be challenged but maybe not as challenged as it was before.

James T. Hackett

I think because of what Karl mentioned as well as the political situation that we’re in today, I think we may find again counterintuitively as I’ve mentioned before that, natural gas becomes a preferred fuel and I’m not sure that permanent situation strangely doesn’t get better over time as opposed to worse. There’s at least a chance of that.

Operator

Your next question comes from John [Wagazino] with Wachovia.

John [Wagazino] - Wachovia

Two quick questions on the operations side. First, can you talk a little bit about the horizontal [inaudible], I was just wondering if you could give a little bit more color than what’s alluded to in the Ops Update.

Charles A. Meloy

This is in the Wattenberg field in Colorado. We’ve now done two horizontal [inaudible] tests and they both have been very successful. We’re learning a lot as we go along. Both have come in at over a million a day, strong looking wells, substantially better than the vertical wells. On average lower decline rates and we’re just continuing to work the program and assuming that everything goes along as it is currently, we hope to expand that program both this year and next and we have a lot of opportunities but no firm commitments yet.

John [Wagazino] - Wachovia

Any idea on the well costs?

Charles A. Meloy

I’d rather not.

John [Wagazino] - Wachovia

Same thing on the Eagleford, I’m curious if you’d just give a little bit more color on expected IP, well costs, that kind of thing.

Robert P. Daniels

On Eagleford, the Maverick [pason] we’re in a deal with TXEO right now where they’re operating the wells. It’s a drilled earn type of thing and they’re in Phase 2 of that program. We like what we’re seeing down there but we’re really early in that one. It’s got a lot of work to do both on what the costs are going to ultimately get down to and what the rates are going to be. We haven’t gotten off a full frac yet on any of our horizontals that we think would be like a production stage frac but we do see very good encouragement in gas and actually liquid rates coming out of there and we’re going to be spending more money in the maverick to try to learn what we need to learn to see how economic it’s going to be but so far so good down there.

Operator

Your next question comes from Rehan Rashid with FBR.

Rehan Rashid - Friedman, Billings, Ramsey

On Heidelberg, could we talk a little bit more about the next step and maybe more importantly implications on additional prospects nearby?

Robert P. Daniels

Heidelberg is really exciting to us and we drove Caesar/Tonga and we had a targeted sand that we thought would trapped against salt which it did and we think we’ve got a very significant discovery there with that information and knowing the mini basin that we’re in and which is the Tahiti Tonga mini basin. We went out and established this position in Heidelberg and we were looking for the same Middle-Miocene sands that we have at Caesar/Tonga trapped against a different salt face inclines separated from the Caesar/Tonga accumulation and encountered exactly what we’d hoped for.

I think that what it’s really done is given us a lot more confidence for the prospectivity of that mini basin and the adjacent mini basin and our ability to predict particular sands within the Middle-Miocene depositional fairways as to where they should be in the trapping configuration, so I think all of this kind of cumulatively gives us a lot of confidence that the prospect inventory that we’ve built around here is very high quality and we will be testing additional prospects in the area probably later this year or into next year. We do want to come back and drill an appraisal well at Heidelberg and we’re trying to work that into the drilling schedule now. We’re looking at probably second half of the year to get back and drill that appraisal well.

Rehan Rashid - Friedman, Billings, Ramsey

As you do more work on the Miocene, is your kind of typical range till holding through that you’re thinking through, I think it was alluded to have been $100 million and change or barrels or is it kind of growing as you understand that on these mini basins here?

Robert P. Daniels

I think that our target, our minimum target size is about 100 million barrels out there, but as we learn more about it, we’re able to high grade our inventory and actually drill the things that have the better potential either from a risk standpoint or from a size standpoint and so in the last couple years we actually have seen our overall field sizes and discoveries getting bigger and we think that’s real positive. We’ve had over 50% success rate over the last four years in the Gulf of Mexico and we think that learning allows us to better high grade which prospects we need to drill and some of that is based on the size of the ultimate trap that we’re testing.

Rehan Rashid - Friedman, Billings, Ramsey

And on the Heidelberg, is that going to backfill Constitution or are we thinking a standalone infrastructure?

Robert P. Daniels

At this point we have both alternatives to us and we haven’t made a decision. We’ll be working that. We can expand Constitution from where it is now or we can put a standalone or work with an industry partner out there as well to build a new foot of the hub type of program.

Operator

Your next question comes from Stephen Beck with Jeffries and Company.

Stephen Beck - Jefferies & Company

My questions have already been answered.

Operator

Your next question comes from John [Emdine] with Wood Mackenzie.

John [Emdine] – Wood Mackenzie

I know you touched on it a little bit but I was wondering if you could talk a bit more about what you’re seeing in deepwater drilling costs, if you’ve seen any downward movement in that in the past few months and your outlook for it I guess in the next few.

Charles A. Meloy

Once again we’re seeing movement in cost, a lot of the contracts are fixed in, we live within those, but on the areas that aren’t fixed we’re seeing movement, it’s not as quick as we would like, and so like we said we’re doing some things to accelerate that. We expect to see significant movement in costs in the current environment in the next two to three months. I think we’ll get a little more color about that next week on our conference call.

John [Emdine] – Wood Mackenzie

I guess I’ve heard numbers for spread costs that aren’t out there that they might come off as much as about 25%, 20 or 25%, is that sort of what you guys are looking at potentially in the next six months or somewhere in a different range?

James T. Hackett

I guess we’re a little bit shy of telling you exactly what you want because we’re going to push for more than what everybody else is... we’re going to be pretty aggressive on this.

John [Emdine] – Wood Mackenzie

Can you talk a little bit more about Shenandoah right now and if not can you give us an idea of when we might hear a little bit more about that?

Robert P. Daniels

On Shenandoah we’re at TD, we’re logging, and so I would expect to hear something very soon. But right now we’re still getting all the data and making sure of what we have before we say anything publicly about it, so I’d look for that very shortly.

Operator

Your next question comes from Phillip Dodge with Sanford Group.

Philip Dodge - Stanford Group

Could you comment on how the new SEC definitions of reserves, at least you know a tentative comment on how that might affect your reserves recording?

James T. Hackett

Prospectively for ’09 or retrospectively for ’08?

Philip Dodge - Stanford Group

Both would be good.

James T. Hackett

Well I don’t think we’ve looked at it for ’08 because the rules don’t really allow us to. As we look at ’09 --

Philip Dodge - Stanford Group

When you get to 12/31/09, how that might look.

James T. Hackett

Right now we’re trying to understand the implications of it as best we can. We’re hopeful that the SEC will in fact go forward with it. As you probably know, that’s on hold along with a lot of other things. Assuming that the current language is used, I think it will have impact for the booking of puds related to a lot of our deep water activities but in the past we’re a little more limited in terms of what we could do in and around the bookings of these larger fields associated with flow tip so that’s probably for us one of the bigger areas. To a lesser extent, the resource plays on shore as you are probably aware there, you’ve got a little more latitude around the pud book. I think for Anadarko, you probably see us be a little more inclined to want to go beyond just approved reserves with the disclosure and we’ll still working through what that will look like. Our database is largely ready to go on that front and my guess is we’ll get that refilled through the course of the year and take advantage of the broader informational disclosure.

Philip Dodge - Stanford Group

Just as a detail, could you give us the current capacity of the Constitution facility and how much is available for tiebacks?

James T. Hackett

The current capacity is roughly 70,000 barrels a day of oil production, the key constraint, and we’re currently working on a production handling agreement for the Caesar/Tonga partnership that would consume essentially what’s left of that available but then we could expand the platform going forward to additional maybe 30,000 barrels a day which could potentially handle Heidelberg or a larger Caesar/Tonga development.

Operator

Your next question comes from Ray Deacon with Pritchard Capital.

Raymond Deacon - Pritchard Capital

I was wondering beyond these two other Marcellus wells that are drilling, what are your plans shaping up to be for 2009 and what kind of transportation agreements do you have in Bradford to be able to monetize that gas?

Robert P. Daniels

On the two wells that we’re drilling, we announced the one, the second one I will say we’ve practiced here just recently, we’re getting very preliminary results back that it looks as good or better than the first well, and it’s still unloading frac wood so we’re real pleased with what we’re seeing up there.

We’re going to be pretty aggressive in the Marcellus. We think that our two partnerships, one with Chesapeake where these two wells are and then down to the south where we’re the operator, we’ll be active in both of those areas, probably moreso in the northeast area. But I think you’ll see quite a few wells drilled this year and quite a bit of news flow coming out of there. Regarding the transportation –

Clay Bretches

Nothing firm on the transportation at this point we’re evaluating our options, obviously we’ll take the lowest cost alternative that’s going to get us to the best market, so we’re in the evaluation stage right now.

Raymond Deacon - Pritchard Capital

Maybe the same question for the Rockies, kind of where you stand, on which pipelines you guys are lining up behind over the next couple years and how much additional takeaway capacity are you hoping to secure?

Clay Bretches

We’ve announced previously that we have taken space both on Ruby which will get us from [Opal] into [Mallin] 200 million a day and also on Bison pipeline it will take us out of the Powder River Basin into the Ventura mid-continent market, Chicago markets, 250 million a day there. So both of those should really help improve the basis for the overall Rockies complex and improve or net backs. You meant Midwest not [Mooconna] because it’s a very different realization as you know.

Raymond Deacon - Pritchard Capital

I guess just curious as far as your deepwater needs, you talked about needing price concessions. Is there... I guess how many rigs do you see yourself looking into? My impression was you had a lot of long term contracts and so there wouldn’t be much ability to cut your costs in ’09.

Karl F. Kurz

Right now we’re excited about our program. As we mentioned during the call, everything we are doing in ’09 we think is value accretive. We’ve looked at everything. We’re moving some stuff around to make sure we drill the core areas on our portfolio both onshore and offshore is very competitive. We have new projects like the Marcellus and Haynesville and Maverick. They’re competing aggressively for capital. Very excited. Our desire is to widen our margins and make these projects even more competitive and more value accretive by getting costs down. I don’t want to leave you under the impression that we have to get our costs down to make our projects work. As Jim mentioned in our big projects work at current cost with $30 oil. So we’re working the cost side just to create more value but not to make our projects economical.

Operator

Your next question comes from Doug [Leggate] with Howard Weil.

Doug [Leggate] - Howard Weil

Couple of things for me. The costs you talked about in the Rockies and the [inaudible], how do you expect your IRRs to evolve over time? Can you talk about where you see those right now in terms of $25 gas at 10% IRR? If those costs are coming down, is it fair to assume that’s one of the last places you’re going to be cutting capital given that they’re relatively resilient?

Karl F. Kurz

We’re going to be looking at capital constraints in all our areas. One of the things that we love about our portfolio is the flexibility it’s provided. We don’t want to get concentration risk in one area in particular. We’ll still be active in the Rockies but I think you’ll see us increase activity in the Haynesville and Marcellus also. As mentioned, Jim said we see $5 price still deliver better than a 10% rate of return. Chuck and his team did a real robust review recently on some of the Rockies programs and we’re using current prices which are $4.50 in Henry Hub and still get a 10% rate of return.

As we lower costs I can’t give you a good forecast on how much incremental return we get for each percent of cost savings but it will be accretive to our program. I fully expect us to be active in the Rockies. One thing that we are committed to do as an executive team is make sure that we can meet our forecast and deliver on our promises and the Rockies is one of the best places we have to deliver rate and reserves and it’s still economical so you’ll see us maintain that program and keep that engine running like we have.

Doug [Leggate] - Howard Weil

The only follow up I’ve got is you gave us some capital numbers for Caesar/Tonga. Can you give us some idea as to how much of an offset you’re going to get in the [Eloise] by running a [inaudible] concentration?

James T. Hackett

The way we’ve expressed that in the past is we’ve avoided almost $1 billion of cost by not having to build an additional hub and the pass through over Constitution through a production handling agreement.

Doug [Leggate] - Howard Weil

Without Eloise benefit it’s basically in the $1 billion as well?

James T. Hackett

Yes.

Operator

Your next question comes from Jeb Armstrong with Calyon Securities.

Jeb Armstrong - Calyon Securities

Turning back to the Rockies, how would your economics look at $5 gas assuming that you didn’t have any basis hedges or firm transportation?

Charles A. Meloy

I think even now without the firm transportation they say that you’ve seen the spreads come in with the lower gas price. They still need to be very competitive within our portfolio and still be value accretive.

Robert P. Daniels

I think it’s important to note too that we subscribe to the firm transportation and put those basis hedges in for exactly this type of environment. It’s not a chicken or an egg issue, it’s because of the projects we had, we wanted to make sure that we have protected the economics regardless and that’s why they were put in place initially, and that’s why we’re subscribing to more capacity on Bison and Ruby also.

Karl F. Kurz

Let me make it clear on the last two questions, we still will be managing our Rockies capital spending to be prudent, not to continue to just ramp up like we’ve been doing this year.

Operator

Your next question is a follow up question from Rehan Rashid with Friedman, Billings, Ramsey & Co.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

On Haynesville, have you guys talked about how much acreage you have?

Charles A. Meloy

We have about 75,000 to 80,000 net acres in Haynesville, all of which is basically held by production.

Rehan Rashid - Friedman, Billings, Ramsey & Co.

And Caesar/Tonga, the $1.3 billion CapEx, how many wells in there or maybe a broad categorization of the costs?

Charles A. Meloy

It encompasses four wells with the completions and then the tieback to Constitution and the upgrade of the Constitution to handle the higher pressure wells from Caesar/Tonga.

Operator

At this time I’d like to turn the call back over to Mr. John Colglazier for closing remarks.

James T. Hackett

If I might just close it out, thank you. This is Jim. Thank you all for joining us today. We’re obviously cognizant of the challenges ahead for our industry and continue to monitor and manage the financial conditions closely. At the same time I think we have a lot to be excited about with some outstanding projects on the horizon and recent expiration momentum.

I want to take the opportunity to remind everybody that we will have a call on February 11 about capital and production guidance as well as the March 10 investor conference here in Houston and hope everybody has a great day and look forward to talking to you next week. Thanks.

Operator

Thank you for your participation in today’s conference. This does conclude your presentation. You may now disconnect and have a great day.

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