EOG Resources Inc (EOG) 2006 Q1 法說會逐字稿

Good day, everyone welcome to the EOG Resources first-quarter 2006 earnings release conference call. As a reminder, this call is being recorded. At this time, I would like to turn the call over to the Chairman and Chief Executive Officer of EOG Resources, Mr. Mark Papa. Please go ahead, sir.

Good morning and thanks for joining us. We hope everyone has seen the press release announcing first-quarter 2006 earnings and operational results. This conference call includes forward-looking statements. The risks associated with forward-looking statements have been outlined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call.

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to be comparable GAAP measure can be found on our website. The SEC permits producers to disclose only proved reserves in their securities filings. Some of the reserve estimates in this conference call and webcast, including those for the Barnett Shale play, may include other categories of reserves.

We incorporate by reference the cautionary note to U.S. investors that appears at the bottom of the Investor Relations page of our website. An updated Investor Relations presentation with statistics was posted to our website earlier this morning.

With me this morning are Ed Segner, President and Chief of Staff; Loren Leiker, EVP Exploration and Development; Gary Thomas, EVP Operations and Maire Baldwin, Vice President Investor Relations.

We filed an 8-K with second-quarter and full-year 2006 guidance yesterday afternoon. You note from this 8-K that we're on target to achieve our 10.5% organic 2006 production growth. Based on the midpoint of yesterday's 8-K, we are projecting our full-year 2006 per unit DD&A, G&A, LOE, transportation, interest and exploration costs to increase only 5.6% over 2005 levels.

You may recall that our 2005 year-over-year unit cost increases were among the lowest in the peer group and we are focused on continuing that trend into 2006. As we discuss in our operational results in a few minutes, you will note there are no changes to our game plan, which is focused on high returns, strong organic growth and low debt.

I will now review our first-quarter net income available to common and discretionary cash flow and then I will discuss operational highlights. As outlined in our press release, for the first quarter, EOG reported net income available to common of $425 million or $1.73 per share. For investors who follow practice of industry analysts who focus on non-GAAP net income available to common to eliminate mark to market impacts outlined in the press release, EOG's first-quarter adjusted net income available to common was $375 million or $1.53 per share.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the first quarter was $714 million or $2.90 per share versus $480 million or $1.98 per share a year ago.

I will now address some of our operational highlights. We generated 10.6% organic year-over-year production growth in the first quarter, a bit higher than our 8-K midpoint due to higher domestic NGL extractions and higher than expected sales to its Atlantic LNG Train 4 in Trinidad. For the full year, we are on target to meet our 10.5% organic growth goal. Note that we expect to hit our 2006 organic growth target even though we had 17 million cubic feet a day shut-in unexpectedly during the first quarter and expect to have 23 million cubic feet a day equivalent shut-in during the second quarter from our Gulf of Mexico operating area due to hurricane-related repairs and equipment availability.

Our full-year 8-K estimates account for these shut-ins, as well as tweaks to reflect higher domestic NGL extractions, slightly lower raw North American gas sales, higher full-year Trinidad takes and lower U.K. North Sea sales.

I will commence our operational review with the Fort Worth Barnett, then I will discuss our strategy regarding other shale plays and our traditional North America Ex Barnett activities and I will conclude discussing Trinidad and the North Sea.

To distinctly summarize the Fort Worth Barnett, all areas are working as well or better than our original prognosis and we had no unusual or unplanned first-quarter production curtailments in this area.

During the first quarter, our Barnett production exceeded our internal goal. We are currently running 14 rigs, 10 in Johnson County and 2 in Erath and 2 in Jack County. Our press release highlighted two recent monster wells, one in eastern and one in western Johnson County.

But rather than focus on individual wells, the three key trends I want to highlight to you are, first, we are continuing to generate very consistent Johnson County results and have moved into a program drilling mode there. As I related to you last quarter, there are two Johnson County well regimes, both of which generate 100% after-tax reinvestment rates of return.

Our Northeast 35,000 acres are generating most of our monster wells, while our western Johnson County 55,000 acres generate the occasional monster well, such as the 5 million cubic feet per day [Clemens] No. 1H well mentioned in the press release.

In recent days, data has been presented by others claiming to have the best Barnett completions. Here is what we know about the one county where we have done the vast majority of our drilling. We are currently the number one gas producer in Johnson County and based on the most recent full month of railroad commission data available, which is January '06, our Johnson County average per well production is 55% to 75% higher than two other peer companies who have recently presented data. Enough said about that.

Our second of three overall key Barnett trends is that we're implementing 500 foot, roughly 37 acre, spacing throughout Johnson County and we continue to be pleased with the results. As we've previously said, we plan to hold off communicating the reserve impact of these down-space wells until year-end to gather more performance history to answer the question regarding new versus acceleration of reserves.

Third, regarding our western acreage, we recently got pipeline connections into Erath and Hood counties and this has allowed us to commence program drilling in both of these counties. As we have previously stated, in Hood and Erath, which we expect will be the least prolific of all our counties, we expect to achieve 0.8 to 1.0 net Bcf for a $1.2 million to $1.4 million targeted completed well cost after optimization of completion techniques, which generates a 30% to 60% after-tax reinvestment rate of return using current gas prices.

Additionally, next month, we will be completing our first 500 foot down space pilot in Erath County. I'll also note that we've shot 3-D over a large percentage of our western county acreage and we are evaluating the impact of less [carstein] on our western acreage drilling program. We plan to ramp up from four to nine rigs on our western acreage by year-end.

To summarize the Fort Worth Barnett, we are meeting all the milestones we targeted. We drilled 93 wells in 2005 and expect to drill about 214 wells in 2006. We expect to ramp up the program further in 2007. We are currently running 14 rigs and expect to exit the year with 23 rigs, all of which are committed.

Our current estimate of the potential overall Barnett reserve range we have captured on our acreage is 3.0 to 4.7 Tcf. This excludes any new reserve values for 500 foot down-spaced wells or for the potential of less carstein on acreage.

Now let me shift from the Fort Worth Barnett to a broader EOG strategy. During our last call, I mentioned that we have accumulated acreage in several possible Barnett clones, including Culberson County in west Texas. Let me elaborate on our strategy and timeline here.

We believe EOG has a technical edge in identifying future shale gas plays and using our Fort Worth Barnett knowledge, we have captured acreage on six onshore North American plays, one of which is our 126,000 acre Culberson County position. By year-end, we expect to have drilled at least one well in each of these five other concepts and we expect to have three of them evaluated, i.e. know whether they are a success or not.

The total cost to acquire acreage and test all six of these concepts is about $90 million and the total reserve exposure is likely similar or possibly larger than our Fort Worth Barnett position. News flow regarding results from these tests will be skewed toward year-end '06 and first quarter '07. So far, the only one of the six we have tested is in Culberson County where we now have a little more data regarding our first short horizontal well that we did on our last earnings call.

The wellhead and additional flow rate of 2.2 5 million cubic feet a day and we have now flowed this well for three months and it is exhibiting flow rates and declines analogous to a western Johnson County short lateral well, which is encouraging. Our vertical well on another part of the Culberson acreage block did not yield measurable amounts of gas we believe because our frac went out of zone. By year-end, we will have one or two additional horizontal drills in Culberson County and we will probably know whether or not we have a commercial success.

Now I will switch to the North American Ex Barnett portion of our portfolio, which we expect to grow about 5% organically in 2006 on the back of 7% growth in 2005. In our Tyler operating area, we're pleased to announce what we believe is a significant north Louisiana Expanded Cotton Valley discovery in our Eros prospect. The [Spillers] 18 No. 1 well, where EOG has a 50% working interest, encountered 330 net feet of pay and tested at combined rates of over 20 million cubic feet a day gross after multiple stage fracs.

These rates are similar to some of the best wells in the nearby analog Vernon Field. We had this prospect in our IR presentation as one of our 2006 big target exploration plays with a reserve estimate of 150 net Bcf and test results now confirm this. We will commence immediate development of the Eros discovery, which adds to our already deep north Louisiana and east Texas drilling inventory. We have at least one additional similar Expanded Cotton Valley exploration prospect that we will be testing later in the year on trend with this discovery.

Overall, we are on track to generate 9.5% production growth from this operating area even though the 30 million cubic feet a day expansion of our east Texas Branton Field has been delayed by six months until year-end because of downstream processing plant delays.

Our south Texas program is on track for 6.5% year-over-year production growth. This area is hitting on all cylinders and we have multiple high rate discoveries. During the first quarter, we drilled five excellent wells in the Sterling Field in Webb County. Two notable wells, the [Slater Ranch U2] and the [BMT/K&H], a "C" No. 1 well had gross flow rates of 11.5 and 12.7 million cubic feet a day respectively. We have 87.5% and 50% working interest in these wells respectively.

In addition to our standard Roleta, Reklaw, Frio, Lobo and Wilcox drilling, we also drilled our first successful Vicksburg sand well. The [Burline] No. 1 well is currently producing 8.2 million cubic feet a day and 150 barrels condensate per day from the Vicksburg W2 sand. We have a 98% working interest in this well, which opens up a new geologic playground for us.

Our Canadian shallow gas program is also on track for 1200 wells this year. Many of which will be developing our new Chinook Field discovery. We also have completed drilling two Northwest Territory exploration wells where we have an approximate 25% working interest.

One well tested a new structure and the other was a delineation well to last year's discovery that tested 10 million cubic feet a day and 3000 barrels of condensate a day, each from two separate zones. Results from the two wells are currently being evaluated and will be disclosed when we have more details.

Our Rocky Mountain activity is on track to achieve about 13% year-over-year organic growth primarily from our Yukon Mesaverde development program where we have seven rigs drilling 40 acre down-spaced wells. As we've previously described to you, we have a deep enough inventory of Utah development locations to keep us busy until at least 2010.

As mentioned, our Gulf of Mexico operating area has suffered $17 million cubic feet equivalents a day of unexpected curtailments relating to pipeline problems and hurricane damage during the first quarter and we expect this to average 23 million a day during the second quarter. We expect these issues to be resolved by the third quarter, but we are dependent on equipment availability and pipeline restoration. Even so, we expect to post about 5% overall organic North America Ex Barnett 2006 growth.

Now, let me move to Trinidad and the North Sea. In Trinidad, during the first quarter, we achieved higher-than-expected sales through Atlantic LNG Train 4 because of delivery shortfalls from other producers. Unfortunately, we don't expect that to continue past early May and our 8-K guidance assumes we will be ratcheted back to our contract quantity of about 20 million cubic a day net for the remainder of the year.

On the drilling front, our second well in Block 4A did not encounter deeper pay sands as we had hoped. Last quarter, we announced the first well was a discovery and the likely block net reserve range total was 200 to 400 Bcf depending on the second well. It now looks like the total discovery size is closer to 200 net Bcf. We are discussing a gas contract for an indigenous market and would expect to have this discovery online by mid 2009.

Additionally, BP has spud our deep Ibis well and it is currently drilling at 7100 feet. This 20,500 foot depth well will be fully funded by BP and assuming no mechanical problems should TD during the fourth quarter. EOG will not pay any cost to drill the well, but will have a 51% working interest and operatorship on subsequent wells and facilities.

At the outset, let me calibrate expectations for this well. It will be targeting deeper sands at about 19,000 feet that have not yet been tested in the prolific Columbus Basin. The concept is that in the overall basin there may be additional hydrocarbons trapped in sands immediately below zones at about 12,000 to 15,000 feet that have proven reserves of over 20 Tcf. The prize is big; all Tcf if successful. We are estimating 740 Bcf to 2 Tcf net impact to EOG.

The risk is that porosity and permeability may or may not be preserved in deeper sands. When the well reaches TD, we will definitely know if it is a negative result, but if logs indicate we have pay, we will be limited to wireline testing only because of the bottom hole pressures involved.

Thus in the success case, expect that you will receive only a qualified answer regarding pay and possible reserves not backed up by an immediate flow test. That will come later.

In the U.K. North Sea, the [Orson] No. 3 well has spudded and is drilling ahead. Because of rig availability and the tight services market, that may be our only U.K. North Sea 2006 drilling activity. We have a couple of prospects to drill, but it is likely it will be 2007 before we can catch a rig window.

I will now turn it over to Ed Segner to review CapEx and capital structure.

Thanks, Mark. For the first quarter, exploration and development expenditures, including asset retirement obligations, were $632 million with less than $300,000 of acquisitions. Total discretionary cash flow for the quarter was $714 million. Capitalized interest for the quarter was $4.4 million. For 2006, as indicated in yesterday's 8-K, our current estimate for capital expenditures is between $2.5 billion to $2.6 billion excluding acquisitions.

As we move to capital structure, at March 31, 2006, total debt outstanding was $933 million and the debt to total capitalization ratio was 16%, down from 19% at year-end 2005. At quarter-end, we had $821 million of cash on the balance sheet. Based on our strong balance sheet and low-risk drilling inventory, Moody's upgraded us to A3 during the quarter, one of the very few E&P companies to hold this high rating.

The effective tax rate for the quarter was 32% and the deferred tax ratio was 52%. For the first quarter, the income tax provision reflected lower foreign accruals. For the full year 2006, the guidant 8-K has an effective tax range of 33% to 37% and a deferral percentage of 40% to 60%.

Guidance for the detailed modeling of the second quarter and updated full-year 2006 guidance was provided yesterday in a Form 8-K filing. We have increased our summer and fall hedge position in recent weeks and Mark will talk in more detail shortly. The form Form 10-Q for the first quarter was filed yesterday and now I'll turn it back to Mark.

Thanks, Ed. Just a few brief comments on our view of the North American gas market. Given the storage overhang, I expect natural gas prices will stable [overhead] between now and November barring a hurricane disruption. And then we expect the market will reset as we move into the winter.

Our financial hedge position was articulated in yesterday's 10-Q as a percentage of North American production, including physical transactions, were roughly 27% hedged or collard for the second quarter at a $9.56 floor/swamp and were 25% hedged/collared in the third quarter at a $9.23 floor/swamp. We have no financial gas hedges in place for November or December 2006 or for any of 2007. We remain totally unhedged on oil.

Now let me summarize what we have said on this conference call. In my opinion, there are five important items to take away from this call. First, the game plan remains consistent with a focus on high ROEs and ROCEs, low debt and high organic production growth. We continue to believe that organic growth generates much higher reinvestment rates of return than growth through acquisitions. We ended the quarter with $112 million of non-GAAP net debt giving us a net debt to total cap ratio of 2%.

Second, we think we are doing a good job controlling year-over-year unit cost increases relative to the industry and that for the second consecutive year, our aggregate year-over-year unit cost increases will be among the lowest in the peer group.

Third, the results of our Fort Worth Barnett Shale development are running slightly ahead of our expectations. Fourth, our North America Ex Barnett program continues to deliver impressive results and the recent Eros prospect discovery only adds to our inventory.

And fifth, we have added a new dimension to our game plan with our multifaceted search for a Barnett Shale clone. We believe we have the technical advantage to pull this off and the risk reward is certainly skewed in our favor. If we are successful, we will again change the entire scope and growth profile of EOG. If we are unsuccessful in finding a Barnett clone, we will simply continue to deliver what we believe to be the best organic production growth and commensurate returns of any large cap independent E&P company in our peer group. Thanks for listening and now we'll go to Q&A.

(OPERATOR INSTRUCTIONS). Robert Morris, Banc of America.

On the extension of western counties in the Barnett, last quarter, you had given us a little bit of an update saying that seven of the eight completions met your success criteria. Can you give us an update on that? Then also I noticed that was the one area where you've increased the per well cost from $1.2 million to $1.4 million. If you can also shed a little bit of light on why those well costs are increasing, whereas they are not in the Johnson County area.

Yes, the reason that the costs have increased out there is basically just due to inflation more than anything else. And the reason we're giving a range there as opposed to Johnson County is that we really haven't settled in on any program drilling out there. To date, up until the last month, what we have been doing out in the western counties is basically moving a rig from Johnson County to drill a selected spot in western counties and then moving that rig 50 miles back to Johnson County.

In other words, we really haven't just camped the rig out there out West and just drilled sequence, sequence, sequence mainly because we haven't had good client connections. Really just in the last month have we gotten pipeline connections out there to primarily the Hood and Erath Counties, so we haven't been able to focus on the cost optimization that much yet.

In terms of your first part of your question, you are correct. Last call, we said we had seven out of eight wells that had looked good and really didn't have the water problems there. I am not sure -- I would guess we probably drilled perhaps another may be six to eight wells over this quarter. We really haven't done that much additional drilling out there and I would say the results are similar if we said that another seven out of eight or six out of eight or so of the wells drilled in the last quarter.

But the bottom line is we haven't drilled an intense concentration of wells out West yet. So we don't have a report that says we have a huge population of wells that we've drilled out there that are statistically significant yet. That will come really beginning with the next quarter's call, Bob.

And a second question on the short horizontal you drilled in Culberson County, you said after three months you had analogous results to Johnson County, but as I recall, that is not yet hooked up to a pipeline. So when you say it is analogous to results, what exactly are you looking at because I guess you are flaring it? Are you getting a full flow as you went to a pipeline or what are you looking at in saying that those are analogous results?

That is exactly right. We are not going to get a pipeline connection out there probably until July and so what we did is we just slowed that well to a flare for the past 90 days and just measured the tubing pressure and production decline rate. You will recall that the well in Culberson County was about a 2000 foot horizontal length and some of our early wells in Johnson County were about 2000 foot horizontal length and we basically gave this Culberson well what we call a small frac. So fortunately we had some wells in western Johnson County that we gave a similarly sized frac to that were about 2000 foot length.

What we can say is that based on the 90 days of production characteristics, this one looks very, very similar to a well with a similar sized frac and similar length in western Johnson County. But that is obviously just early days. What it does say is the well didn't start out at 2.25 (technical difficulty) a day and then just immediately just drop (inaudible) substantial rate. So to us, we believe that is good news.

And then lastly on the vertical well in a different part of Culberson County, you said you fraced out a zone. Can you just go back and frac in the zone? It is a vertical well. Can you just go back and open up the right zone to frac in the [still test type] well?

Probably not in that well. That well was a vertical well. We had some real hole difficulties there and basically we had the hole was considerably enlarged and we don't think we got a very effective cement job in that well. Consequently, it didn't really surprise us mechanically when the frac likely went out at the zone. So in that particular wellbore, it would probably be cheaper for us, more effective, to drill another well, which is what we will do in that particular area.

Gil Yang, Citigroup.

I have two timeline questions. If you look at the Culberson area, considering Fort Worth's Basin, it has been about 2.5 years since you started filling a lot of wells in the area. If you were to take that as a timeline, where would you say, in terms of technology, you are or your understanding about how to frac wells in Culberson -- understand you've only fraced may be a couple -- where do you think you are in that timeline that you would draw for the last 2.5 years in the Fort Worth Basin?

Well, I would say, Gil, from the time we started in Johnson County -- it probably took us a year in Johnson County to understand how to drill and frac the wells. So what we are able to do in Culberson County is we basically bypassed that year of trial and error in there. So I would say we are in a timeline where if we can get two or three or four decent wells in Culberson County, if we have success in those wells, we are going to feel really good about it there in terms of things.

So the next horizontal well we drill will be a longer lateral and it will be a frac that is of the technology that is pretty similar to what we are currently doing in our current wells in the Fort Worth Barnett.

The first well, the one that we have data on now, was basically -- I guess in a conceptual way, it was basically let's drill a short lateral, let's do a small frac and let's find out if this formation is going to yield enough gas to roast a marshmallow or give enough gas to make a commercial gas well. And that was the goal. And if it was enough gas that would only roast a marshmallow then we'd probably have to pull up stakes and say this was a good idea, but it didn't work. And fortunately that wasn't the case.

So now we know there is pretty decent gas coming out of it. So the real issue is, okay, now, let's go and if we drill a 4000 foot lateral and give it a frac like our typical Fort Worth Barnett wells, what kind of well are we going to get and that is what we will be trying to do on the next well we drill.

Okay. And then sort of analogously, how long is it going to be before you optimize Erath and Hood with accelerated drilling?

We are out there right now in those areas with four rigs and the gameplan is by the end of the year to have nine rigs. So I'd say we are commencing what I would call serious drilling out there now and we are probably about three weeks into what I would call a serious drilling phase. So far, it has been poke around drilling phase on a very large acreage base, but now it is moving into the serious phase is what I would call it.

Last question is the rig for the Eros prospect or the new drilling you're going to do there, where are the new rigs going to come from?

We have got a rig that is drilling in Vernon now and then we will be finishing this well and moving right over to Eros. So we are contracting several new builds. As a matter-of-fact, we've got 19 under contract.

Okay. But in terms of your original program, is the activity or is the success of Eros taking a rig that would've been allocated for someplace else to Eros?

Yes, because we have got, as Mark had mentioned earlier, there at Branton, we have got curtailed gas that we're going to be drilling here at Eros because we can put this well online rather than wait till November to have first production.

Benjamin Dell, Bernstein.

I had two questions; one is just a technical one. How much flexibility do you have in terms of stripping out NGLs and varying that quarter-by-quarter? My second question was really around your U.K. strategy to see if anything has changed there. Obviously the environment has become a little tougher, but obviously natural gas prices there were very strong. Have you had a change of heart with respect to where you see that business going?

Yes. Let me address your NGL question. The amount of flexibility we have depends on the area and what the specific contract is with the NGL stripping plant, but in rough terms, we have -- for example, in the U.S., we have changed the midpoint of the range on our 8-K from 6250 barrels a day to 7250 barrels a day of NGLs for the full year. And that represents our best guess of the elections that we will be able to make, that we believe gas prices are likely to be depressed relative to NGL prices at least through November. So that is the likely range we would see. So it is not a huge range. It is only about 1000 barrels a day or about 6 million gas a day of equivalents is the swing we are anticipating.

On your second question, on the U.K. strategy, yes, you are very clearly right. Our things have changed radically in the U.K. since we entered it there. When we entered it, we had a relatively open field to go to the majors for farm-ins and we were pretty hopeful that U.K. gas prices were going to be robust and what has happened is, wow, they got a whole lot more robust than we thought, but it also attracted an intense competition for farm-in deals from majors.

So we've shifted more to the organic route and the organic route is just slower and so basically what you're seeing in our slowdown on activity right now is two things. One is we are basically in about a one to a probably year and a half hiatus as we shift gears toward organically generating prospects in the North Sea and it's just going to take some time for us to get that done as opposed to farm-ins.

And then the second point is since we don't have a continuous program, we have a well here and a well there to drill and the rigs are so tight, we almost have to beg people to get a window in a jackup rig situation and that is just very difficult to even secure a rig for a one oil deal.

So we are in there for the long run, but we are also cautioning people don't expect production growth from the U.K. for us likely this year or in 2007.

David Heikkinen, Pickering Energy Partners.

Just talking about your hedges, have you locked in any basis hedges as well for the summer?

No, we have not. We've historically -- well let me change that answer. In the U.S., we have not and historically, we have not done any basis hedges at all. We have done some basis locks in our Canadian area.

What type of basis would that be?

We will have to get back to you on that specific number on that, but we are not a company that really has played the basis game very much. Mainly we just lock it in at the hubs.

The variance on production focused in the Gulf of Mexico, a lot of appetite for Gulf of Mexico assets, just generating cash there. Is that something you'd consider monetizing? You don't really need additional cash given your balance sheet, but what are your thoughts there?

Very unlikely we would monetize it. As any company could now, we could pick any of our assets in our portfolio and put them up for sale and get a crazy high price for it. But it is very likely what we are going to do with our remaining Gulf of Mexico assets and the total production -- if we had all of our Gulf of Mexico assets online right now, total production in front would probably be about $40 million a day. So it is not a big chunk of our total portfolio at all.

But we are probably just going to produce them to depletion. We think we create more value that way. So don't look for any significant property sales from us this year unless it is a very unusual circumstance and the same thing on the acquisition front. Don't expect that you're going to wake up one day and see a big headline where we have made some major producing property acquisition. That is very out of character and very unlikely that we would do that.

So can you comment on the [four sevens] deal then since you're not going to buy it?

We have as much interest in that one as we --

Have in all of them?

-- had in [Chief].

Okay. On your actual well count and rig count for Johnson County going from 10 to 14 rigs, are those primarily focused in the Northeast area, or is there a split between Northeast and West that we can think about?

We are going to be bringing in five rigs to the Western extension, and then the other rigs will be probably pretty well split between Western Johnson and Northeast Johnson.

Okay. That was it. Thanks, guys.

Joe Allman, RBC Capital Markets.

Could you to talk about the industry data that you are hearing about in Culberson County and what you think about that? Is it encouraging or is it mixed?

I would say so far the news is pretty mixed in Culberson County. There have been a lot of drilling issues there. A lot of operators have not been able to get their wells down, certainly in a horizontal sense. And when they do get them down, they have had difficulty completing them. I think ours is the first horizontal well to be drilled, cased and completed in Culberson County. And to my knowledge, the wells that have gone on in the southern part of Culberson County have not had the results that we have had.

Yes, our view there is that there is a ton of gas in the Barnett and Woodford Shale there, but the key is you have got to be at the right depth and most people in the Delaware Basin have acreage that is probably too deep. In other words, they may be at depths of 10,000-11,000-12,000-13,000 feet and unfortunately, the cost to drill a horizontal well out there is probably going to be $6 million, $7 million, $8 million and we don't think that the economics are going to work there.

And then the second point is there is a lot of tectonic stress in that basin, a lot of uplifts, a lot of geologic turmoil that has existed there and some people, for example, immediately to the south of our acreage, there was an extremely high stress area and people have had all kinds of difficulty drilling wells, particularly horizontal wells, in that high stress area.

So it appears to us that our acreage or the vast majority of it is at the right depth, i.e. similar to the Barnett Shale depth, the Fort Worth depth and is also in a relatively low stress area. And that is why we picked that acreage in that location. And hopefully, that is why we believe that particular part of the basin where we are at is going to work where other parts of the basin it just may be tougher to make it work even though all parts of the basin have a ton of gas in place.

That's helpful. And then Mark, on Trinidad, could you repeat what you said about the Train 4 and the problem there and what's the impact to you again?

Yes. We have a contract with Atlantic LNG Train 4 that basically -- we will be selling about 20 million a day net and the contract terms are basically -- the price we get at the wellhead is linked to Henry Hub directly and I won't go through the formula, but it is a price that is superior to the indigenous market.

And what happened was when Train 4 started up, some of the other people who had bigger portions of supply contracts for Train 4 had some difficulties in supplying their share of the gas and we had surplus deliverability available and we were able to make up for the shortfall and that shortfall has continued really into early May.

But we are advised that the other producers are probably going to be able to come online with their share of the volumes sometime probably within a matter of weeks. What we are assuming in our 8-K that we just issued last night is that we're going to be ratcheted back to 20 million a day for the rest of the year really starting probably within a couple of weeks.

That's helpful. And lastly, in the Rocky Mountains, it seems like you're doing mostly development drilling. Do you have any exploration drilling going on?

Yes, Joe. We are exploring in the Rockies in a number of basins, particularly the Green River Basin, the Uinta Basin, the Williston and the Powder, in the Uinta Basin for example where we were doing a lot of drilling in the eastern Uinta on our Chapita wells area. We think that there could be similar type accumulations to that Chapita wells asset in the western part of the basin and we will be drilling five Wildcats out there this year. In fact, one is drilling now.

In the Green River, we are looking at a lot of horizontal targets. In the Powder, we're also looking at 3-D targets next to discoveries that we have had in prior years. In the Williston Basin, we have been operating here for several years in the Bakken horizontal play and believe that there is more of that to be done and have a couple of Wildcats drilling now.

Very helpful. Thank you.

David Snow, Energy Equities.

I am wondering if you could repeat where you said you had heard in Culberson County that there were likely to be more problematic results. Which direction was it? Did you say to the West or to the South?

Really a little bit of both. There are active tectonics going on, basin range scale tectonics going on and mainly to the West in the area called the Salt Flat graben, that does, we think, have impact in the western part of the Delaware Basin in local areas. Now how far south that goes, we don't know. But we do know that in the area that others have been drilling in the southern part of Culberson that has been a big issue.

And when you stand back and look at shale plays as compared to say coalbed methane plays, do they appear to have better odds of success predrill? How do you look at them on a comparable basis?

I guess my personal feeling is that they do have better odds of success. We don't know as much about coal obviously as we do about shale. It seems like a simpler game to us because we understand the parameters that go into it in terms of depths and maturities and thicknesses and so on. In most of the shale plays, it has worked. The exception to this would be the Antrim in Michigan being a biogenic play, but most of the shale plays are actually basin-centered gas type of plays. So water is not as big of an issue if you can keep from fracing into it that is as it is in coalbed methane.

In other words, you don't normally have to dewater these plays before you get the gas, so the decline curve is much more rate of return friendly.

Having said that, I think that there are going to be really good plays like the Barnett and maybe second order plays. Just like in coalbed methane, there is a champion play in the San Juan Basin then there are in the other plays. We think there are going to be other Barnett scale plays out there, but perhaps Barnett has the best economics of the shale plays that will end up being productive.

Would you think that if you were looking at your five others that you would put a 75% or 80% preassessment expectation on them?

We are not going to give any statistics on odds on it. We'll see how they play out.

I was just trying to feel you out for the general set of odds you would put on shale plays.

Not going to give you any percentages. Sorry.

Okay. Thank you very much.

Leo Mariani, Jefferies & Company.

I am curious as to how many wells you guys think it's going to take to delineate that Eros discovery over there and what do you think the timeline is?

Well, the timeline is that -- we have any area there that is maybe somewhere between 3000 and 5000 acres and the initial well was drilled by another operator. If we have 50% in the total prospect and we divide that operatorship into two halves of that prospect, the operator is currently moving in and rigging up for the second well.

As we mentioned a few minutes ago, our rig will be there in, what, about a month and a half, about 40 days. So that will be two rigs running and I suspect really when those three wells are down, we will have a pretty good idea of what the deliverability is, certainly the rocks in this prospect and then we will have to start stepping down the plank. But it is interesting that there are wells drilled as much as 400 feet off the crest of this that are productive. So we think we have got a pretty good reason to believe that this is a very sizable discovery.

Okay. Can you folks give any update on your activity in the Wolfcamp play?

Yes, we have drilled now a total of about 24 wells in the Wolfcamp play. You are talking about the Wolfcamp play in New Mexico I assume?

Yes, I am.

We drilled a total of 24. We have 16 of those online, 4 currently drilling and 4 waiting on completion. That is really where we are on the drilling side right now. That is probably about all we can say about it.

Are you guys seeing pretty consistent results out of those 16 wells online in terms of flow rates?

We are doing some experimenting with our completions there. We have not really optimized that yet. We're still trying some different ways of staging and numbers of stages, that sort of thing, so I would say the results are not at a consistent stage yet.

Okay. Just turning to the Barnett real quickly here. In terms of wells you guys are drilling in Johnson County, what kind of timing are you seeing on those in terms of from spud to pipeline connection?

In western Johnson County, fourth quarter of '05, we were taking 17.5 days per well and first quarter '06, they have averaged 14.5 days per well. That is drilling time. Of course, then we are congregating the wells before we do the completion. So, yes, we have got about five or six clusters of wells just waiting on maybe one or two additional wells in those clusters to be drilled before going ahead with the completion. We have drilled about 70 wells in there this year and we have completed about 40.

[Dean Barber], Deutsche Asset Management.

Just a quick question on your hedges, what you think about them. Mark, I know historically you haven't been one to want to go out and hedge a gas price, but I didn't quite hear what you said on the call in terms of what you think the average price was going to be for the year. But it seems like your 25% hedge for Q2 and Q3, just what the thoughts are on that percentage and potentially increasing it and why or why not you haven't done that at this point?

What I said on the call is that based on our supply demand numbers that we run given the storage overhang, it looks like to us that natural gas needs to stay below resid between now and the start of winter, which means that our read is gas probably needs to stay in the range of $7, $7.25 assuming oil prices stay where they are during that period. So when gas popped up to roughly $8 a couple of weeks ago, we layered on some more hedges for the summer and the fall just on the basis that that was higher than resid.

So we just believe that during the next six months, we just need to work off the storage overhang and then we believe that the clock resets effective November 1 and then we go into the situation again where it is a function of what is next winter going to be like or so. That is why at this stage we are totally unhedged commencing November 1 and for '07.

Makes sense. And then just another question. Your cash flow balance, just what your thoughts are in terms of what you're going to be doing with that. Obviously it has been growing. What are the plans there?

Yes, number one, we are a company that just feels very comfortable with low debt right now. We have close to no debt, net debt. What we want to do is we want to see how the results of these six Barnett clones turn out and we want to see how much we want to scale up our Fort Worth Barnett activity for next year and then we will just buy it where we go.

In other words, if we have a lot of success in these Barnett Shale clones, let's say three or four of them work and we know we're going to have to feed a significant amount of new capital into development projects for those. So we are keeping our debt ultralow until we really say what our capital requirements are going to be, which is really going to be a function of how many wells do we really want to drill next year in the Fort Worth Barnett Shale and then how these other shale plays work.

John Herlin, Merrill Lynch.

A couple of quick ones. Your CapEx went up to about $600 million. It's up about $200 million from last year. Went through your disclosures, how many wells did you drill? I didn't find it anywhere?

During what time frame?

Just the first quarter, how many wells did you drill?

In 2005?

No, in the first quarter.

First quarter.

We will have to get back to you on that. We don't have that at the tip of our tongue.

No problem. Next one. Production sequentially was kind of flat. You had been giving guidance that that is fine. I was wondering, since you are very active in your drilling, how much do you think you have behind pipe right now that is just awaiting hookup?

Well, we have got basically between the Branton Field and the stuff that we have offshore -- you say about 20 million a day plus probably another 20 million a day right now that is immediately in the Branton Field, we probably have 40 million a day today in North America plus probably another 5 million to 10 million a day in south Texas. So we have got quite a bit that is just backed up due to downstream things. I'd say 50 million a day right there.

Super. Last one for me is on basis. What are you seeing currently?

I don't know if we have -- we are seeing it stay relatively flat for the last four or five months, but it is obviously wider than it has been historically and our guess is it probably, if gas prices go up to $9 or so this winter or whatever that we may see basis expand a bit more really. So I believe we are probably just going to be stuck with a wider basis than we had four or five years ago.

That's great. That's it for me.

Joe Magner, Petrie Parkman.

I just wanted to circle back to the Rockies. You mentioned the inventory in the Mesaverde that will last you through 2010. Just curious if that is based on 40 acre spacing or 20 acre spacing and then also are you including anything for any of the deep potential there and what are your plans to test that additionally?

What we are talking about there is not anything to do with the deep Big Piney. We are still basically saying -- we are studying that, a but we are not telling anyone to assign any value to the deep Big Piney to our stock. What we are talking about in the program going to 2010 is in our Vernal, Utah area there and that would be taking it to 20s and then even considering going down to 10 acre spacing possibly in the Vernal, Utah area.

That's all I have got. Thanks.

David Heikkinen, Pickering Energy Partners.

Actually the question on the Wolfcamp was answered.

Gil Yang, Citigroup.

On Ibis, you are carried for the well cost up to I think 50 million. If it overruns, do you have to pay?

No, there is no cap on the well cost. So we are carried until it gets to TD.

Monroe Helm, CM Energy Partners.

Great results as usual. I had to step off for a second. So you might have already answered this. I think early on in the call, you talked about increasing the drawing activity in the Barnett Shale and I just wondered what your outlook is for additional rigs that you're going to need and whether or not you're going to have any built especially for you?

Yes, we have contracted for 19 new builds. We are going to get seven of those delivered through '06 and the balance will be coming just over the next 9 to 10 months.

And how many of those should be for the Barnett Shale?

All 19 of them are.

All 19?

Yes.

Congratulations.

Thanks, Monroe.

There are no further questions. I will turn the conference over to Mr. Papa for any additional or closing remarks.

Okay. I don't have any additional remarks, so thank everyone for paying attention during the call.

Thank you. That does conclude today's conference call. We thank you for your participation and have a nice day.