EOG Resources Inc (EOG) 2006 Q2 法說會逐字稿

Good day, everyone, and welcome to the EOG Resources second-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 second-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 to this call.

This conference call contains certain non-GAAP financial measures. The reconciliation schedules for these non-GAAP measures to the comparable GAAP measures 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 and statistics was posted to our website this morning.

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

We filed an 8-K with third-quarter and full-year 2006 guidance yesterday afternoon. You will note from this 8-K that we still expect to achieve our 10.5% organic 2006 production growth. As we discuss our operational results in a few minutes, I'm sure you won't be surprised to here 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 second-quarter net income available to common and discretionary cash flow, and then I'll discuss operational highlights.

As outlined in our press release, for the second quarter, EOG reported net income available to common of $330 million, or $1.34 per share. For our investors who follow the practice of industry analysts and focus on non-GAAP net income available to common to eliminate mark-to-market impacts and other onetime items outlined in the press release, EOG's second-quarter adjusted net income available to common was $285 million, or $1.16 per share.

For investors who follow the practice of industry analysts who focus on non-GAAP discretionary cash flow, EOG's DCF for the second quarter was $623 million, or $2.53 per share, versus $556 million, or $2.29 per share a year ago.

I'll now address our operational highlights. We exceeded the midpoint of our second-quarter 8-K guidance due to higher domestic gas and NGL sales and higher Trinidad gas sales. For the full year, we're on target to meet our 10.5% organic growth goal, but we will note that the mix has changed a bit. We expect higher full-year Barnett and Trinidad gas sales and lower overall domestic non-Barnett gas sales than we'd previously forecasted.

The lower domestic gas sales are caused by a likely full-year 2006 delay in returning about 20 million a day of Gulf of Mexico production online, currently shut in due to delays in hurricane-related infrastructure repairs and by a full year of processing plant delays in commencing meaningful sales from our 30 million a day East Texas Branton Field. I think it speaks well regarding EOG's inventory that we still expect to hit our volume target in spite of these unforeseen delays.

I'll commence on operational review with the Fort Worth Barnett; then I'll discuss our strategy regarding other shale plays and our traditional North America X-Barnett activities; and I'll conclude discussing Trinidad and the North Sea.

The Fort Worth Barnett is an area that is currently overachieving for us. We recently achieved net production of 140 million cubic feet a day. Our original plan called for a year-end 2006 exit rate of 155 million cubic feet a day, so we are handily above our internal goal for this area. The current production rate is 100% organic.

We are currently running 15 rigs, 11 in Johnson County and four in the western counties. Normally in our press release, we highlight a couple of Johnson County monster wells. These periodic wells had become somewhat routine, so we have discontinued highlighting individual wells and will focus more on three key trends that provide a broader context.

First, our Johnson County drilling program is continuing to generate consistent results. We've spudded about 100 Johnson County wells here to date. Of these, we have put 60 wells to sales, 11 are currently drilling and we have about 30 wells completing or waiting on pipeline. Direct after-tax rate of returns are running approximately 90% and per-well costs and reserves are continuing to be about what we expected for the thousand-foot-spaced wells.

We have not made any further dramatic well completion or frac technology breakthroughs, but we have made big improvements in drilling time for wells, which will allow us to drill the same number of wells with fewer rigs. The Johnson County program has now moved into the execution phase, and we like to think one of EOG's strengths is drilling hundreds or thousands of repeatable wells.

The second trend is that we are implementing 500-foot roughly 37-acre spacing throughout Johnson County as a routine matter, and continue to be pleased with the results. This has now become so standard for us in Johnson County that I won't report this as a key trend in future quarters. As I've previously stated, we will communicate the reserve impact of these down-spaced wells at year end after we've got more production history, sort out what portion of production is new recovery versus acceleration of reserves.

Third, regarding our acreage outside Johnson County, we've now drilled one or more wells in each of six different counties -- Wise, Jack, Parker, Erath, Hood and Somervell. The only two counties where we haven't yet drilled a well are Palo Pinto and Hill, and we expect to drill our first wells there before year end.

To give you an idea of the size of our acreage spread, it's 75 miles north-south from our Jack acreage to our Somervell acreage, and simply put, we haven't yet drilled a sufficient population of wells in any one county using our latest Western Barnett completion technology to ascertain specific costs and reserves on a county-by-county basis.

Compared to the 60 wells we've completed year-to-date in Johnson County, we've completed only 12 wells year-to-date in all of our Western acreage, six in Jack County and six among the other counties. At this time, the only county where we feel we have enough consistent data to make a definitive technical call is Jack County, where we have 55,000 acres.

In Jack County, the six wells we drilled have averaged 1.0 net Bcf and generated a 30% direct after-tax rate of return, and this is without the advantage of program drilling cost optimization. So we feel on a Jack County program basis, we can likely get direct returns to the 40% to 60% level for our 55,000-acre position.

In Hood, Parker, Erath and Somervell Counties, we need to drill a larger population of wells. In Erath County, we have a three-well, 500-foot down-spaced pilot underway and it's too early to assess results.

Two things are certain regarding all the Western acreage. First, because the per-well reserves are less than Johnson County, we have to implement step function changes in our drilling and completion methods to get the costs in line to achieve appropriate economics, and we are doing so. And second, we have implemented a modified frac technique to adjust for the center pay in the West.

What you should expect regarding progression and news flow from our Western acreage is likely county-by-county results similar to the report we've given you this quarter regarding Jack County. I also want to remind everyone that most of this Western acreage is expected to generate between 0.8 and 1.0 net Bcf per well, generating a likely 30% to 60% direct after-tax rate of return. The prize here is literally thousands of potential 1-Bcf drilling locations on our Western acreage.

Now let's shift from the Fort Worth Barnett to a broader EOG shale gas strategy. Last quarter, we mentioned six potential North America Barnett clones that we expect to have tested by year end. We also cautioned that news flow would be skewed toward year end '06 and first quarter '07. True to our word, we don't have any new news flow now, except to let you know that three of these six have well activity in progress.

We're currently drilling our second horizontal well in Culberson County. We are drilling another separate shale gas play, and we're flow testing a horizontal well in a third shale play, all in different regions of the U.S.

Now I'll switch to the North America X-Barnett portion of our portfolio, which continues to perform well. We're having an outstanding year in South Texas and expect to generate 6% year-over-year production growth. Each quarter, we continue to have multiple high-rate discoveries. Three good wells we completed during the quarter were the Kirk Gas Unit #4, and the Slator Ranch W#1 and #33 Wells, which IP'd at gross rates of 13, 18 and 16 million cubic feet a day, respectively. EOG has 88% working interest in the first two wells and 50% working interest in the last well.

In our East Texas/North Louisiana operations, we completed two good James Lime wells recently in Louisiana. The [Motz] #1 and the McKenzie #1 wells IP'd for 6.2 and 5.1 million cubic feet a day. EOG has 100% working interest in both wells. Our Rocky Mountain activity is on track to achieve about 13% year-over-year organic production growth this year. Unlike some of our other operating areas, this growth comes from a plethora of consistent 1-million cubic feet a day wells, so we won't highlight any individual wells for you.

In our Mid-continent operating area last year, we expanded our core Hugoton Deep acreage by adding 900,000 acres of deep rights in the Oklahoma Panhandle and Southwest Kansas. During the past quarter, we made give 6500-foot-deep 3-D supported moral sand discoveries that will add 15 million cubic feet a day of sales commencing in August at very high rates of return. We view this large acreage (indiscernible) as a significant growth opportunity in an area where we've drilled 1000 wells since 1996.

In New Mexico, we recently completed several good wells in our Wolfcamp horizontal play. The [San Saba B-12 Fee #2H] and the [Congo B-10 Fee #2H] IP'd at 6 million and 4 million cubic feet a day. EOG has 75% and 50% working interest in these wells.

Due to wet weather issues, our Canadian shallow gas program is behind schedule and we have slightly lowered our 8-K guidance to reflect the fact that this production will be coming online later in the year than initially anticipated. We expect to drill our full complement of about 1200 wells this year, but the production online timing has slipped.

Now let me move to Trinidad in the North Sea. In Trinidad, BP is currently drilling the Deep Ibis well at about 16,000 feet, on their way to a target of about 20,000 feet. Assuming no mechanical problems, this well should reach TD by our next earnings call.

As I did last quarter, let me calibrate expectations for this well. When the well reaches TD, we will definitively know if it's 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, 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 UK North Sea, the Arthur #3 well was a success and flow tested at a gross rate of 68 million cubic feet a day. We have a 30% working interest in this well. This well is currently being connected to sales. This will be a great high-return well, but we expect the well to have only a moderate reserve life.

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

Thanks, Mark. For capital expenditures for the second quarter, exploration and development expenditures, including asset retirement obligations, were $637 million, with less than $6 million of property acquisitions. Total discretionary cash flow for the quarter was $623 million. Year-to-date, exploration and development expenditures, including asset retirement obligations, were $1,269,000,000, with less than $6 million of property acquisitions.

Capitalized interest for the quarter was 4.7 million. For 2006, as indicated in yesterday's 8-K, our current estimate for capital expenditures is between $2.6 billion and $2.75 billion, excluding acquisitions. The increase from the May 8-K filing, which was 2.5 to 2.6, is primarily due to increased service cost.

Now to capital structure. At June 30th, 2006, total debt outstanding was $893 million, and the debt to total capitalization ratio was 15%, down from 19% at year-end 2005. At quarter end, we had $759 million of cash on the balance sheet, the effective tax rate for the quarter was 29%, and the deferred tax ratio was 36%.

For the second quarter, the income tax provision reflected a Canadian federal tax rate reduction of $19 million and a provincial tax rate reduction of $13 million in Alberta, partially offset by a $5 million increase caused by the revision of the Texas franchise tax law. If you exclude those three items, the effective tax rate for the quarter was approximately 34%. For the full year 2006, the guidance 8-K has an effective tax rate range of 32% to 34% and a deferral percentage of 40% to 60%.

Guidance for the detailed modeling of the third-quarter and updated full-year 2006 guidance was provided yesterday in a Form 8-K filing. We plan on filing the Form 10-Q for the second quarter later today. You will note an increase to our 2007 oil hedge position since the early July 8-K filing.

With respect to our upcoming analyst conference, for our 2006 analyst conference, we have now decided to host a Barnett Shale field trip as part of the conference. And thus, we will have new dates for the conference. Those dates will be November 29th and November 30th in Fort Worth, and more details will be forthcoming.

Now I will turn it back to Mark.

Thanks, Ed. Let me make a few comments regarding our view of the natural gas market in North America and our current hedge position. The recent nationwide hot spell has obviously had a salubrious effect on the natural gas markets and the storage overhang. But we think there are more fundamental forces at work than just weather that makes us sanguine regarding 2007 natural gas prices.

We believe that domestic production has grown only slightly, if at all, despite high drilling levels, as Gulf of Mexico declines have offset onshore production growth. Canadian production growth has been rather tepid, so we think the overall effect of increased North American gas drilling has been only to arrest the chronic production declines of the past several years.

Our financial hedge position was articulated in a recent 8-K. As a percentage of North American production, we're about 26% collared or hedged for September and October of this year, and only about 7% hedged for November and December of this year. We have about 4% of our 2007 North American gas production hedged at a $10 Henry Hub price. Regarding oil, we have no oil hedges for 2006 and have 3000 barrels a day hedged for calendar year 2007, hedged at an average price of $77.50.

Now, let me summarize. In my opinion, there are six important points to take away from this earnings call. First, as always, the game plan remains consistent, with a focus on a high ROEs and ROCEs, low debt and high organic production growth. In these times of very high corporate acquisition and producing property prices, we think now more than ever organic growth will generate a high reinvestment rate of return and growth through acquisitions.

Additionally, we ended the quarter with $134 million of non-GAAP net debt, giving us a net debt to total cap ratio of 3%.

Second, we think we're doing a good job controlling overall year-over-year unit cost increases relative to the industry for the second year in a row. We believe our absolute overall unit costs rank either the lowest or among the lowest in the peer group and that this gap is increasing each year.

Third, relative to expectations, July to October North American gas prices have so far not been as negative as many had predicted. This relative strength reaffirms our belief that 2007 Henry Hub prices will be pretty robust.

Fourth, our Fort Worth Barnett Shale results are running ahead of expectations, and county by county, we're beginning to make good technical progress on our western acreage, beginning with Jack County. Overall, we expect to drill about 225 Barnett wells this year and roughly double that in 2007.

Fifth, our North America X-Barnett program continues to generate impressive results. And finally, we've added a new dimension to our game plan with our multifaceted search for a Barnett Shale clone. We're into the testing phase regarding several of these plays and we believe the risk reward is certainly skewed in our favor.

If we are successful, we will again change the scope and growth profile of EOG. If we are unsuccessful in finding a 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 joining us today and we will now go to Q&A.

(OPERATOR INSTRUCTIONS) Scott Hanold from RBC Capital Markets.

Good morning. You talked about in the Barnett Shale that you've seen some improved drilling time. Can you kind of give a little bit more color on that?

Yes, we've just taken delivery on a new, smaller, more efficient rig, and we're seeing our days be reduced already, with just having drilled a couple of wells. On the average, we're taking somewhere around 15 days to drill these wells. And we think we will get these down in the 10s and maybe even lower as far as days per well.

Okay. Fair enough. I guess you are ahead of schedule in the Barnett Shale. Do you sort of have a new target for year end at this time?

Yes, but we're not going to pin ourselves down on a production target on that area. And I think the days per well that Gary gave you there is kind of for our western area there primarily.

But what you'll note -- and I think we've got an IR presentation up on our website here this morning -- that has changed a bit is that our earlier expectation was that we would finish the year with about 23 rigs in the Barnett. We now believe we can accomplish our goal of drilling about the 225 wells by finishing the year with only 18 rigs running.

So what we are seeing is it's going to take us less rigs to drill a certain number of wells than we would have expected, say, six months ago, simply because it's taking us less days to drill each well. So that is one way we are seeing a lot of efficiencies in the Barnett.

And that is one way, as Gary mentioned, that we believe we're going to attack the cost side equation in the western counties, is ultimately getting the days per well down to about 10 days per well in the western counties there, to get the economics right, where we can attack it and have good economics at about 1 Bcf per well.

How many rigs would you need, do you think, in 2007 to sort of hit that 450 target per well that you want to drill?

We will probably average somewhere in the 18 to 20 rigs.

18 to 20, that was?

Yes.

Okay. One last question, In those unidentified shale plays you guys are looking at right now, is there opportunity to pick up additional acreage if you see what you like or is it pretty tight?

Yes, in pretty much all of them except Culberson County the game plan we have is we have an acreage position and we believe that we can -- and we're drilling a pilot well or two in each of these -- the other shale plays. And we believe we can expand that acreage position if we get the positive results from the first well or two.

Okay, thanks, guys.

Tom Gardner with Simmons & Company.

Good morning. Mark, with respect to the Fort Worth Barnett Johnson County down-spaced wells, I'd be interested in getting your estimates on what you're currently modeling as per well gross reserves and what percent of the total is captured versus acceleration?

That is just what we said we probably didn't want to give out until we really had a pretty good handle on it, and that's probably going to be at the end of the year. What we can say right now is there is not much difference if you just stood back in the performance of the 500-foot wells and the 1000-foot wells.

But before we just make a bold statement like that, we want to get some more production history and make some sort of assessments as to whether in fact some of the reserves coming out of the 500-foot wells are in fact acceleration reserves, i.e. that are just taking the tail-end reserves that would ultimately be produced from the 1000-foot wells in years 15 through 25 and accelerating that.

So we'd just like to defer answering that until around year end, when we can give you a clearer picture.

But one of the advantages of having the analyst conference here in late November up in Fort Worth is we believe we can -- at that time, we can give you a more clear picture, particularly of the progress we're making in the western counties, and answer some of these questions with a little more clarity. And perhaps at that time, we can give you a little more clarity on what these 500-foot wells are doing as far as acceleration versus new reserves.

Okay. One other question, with respect to your comments on organic growth versus acquisitions. Do we take that to mean the Company will continue to remain on the sidelines with respect to acquisitions or have you begun to actively screen potential targets, or where would you like to be bigger?

Yes, I think you can take that statement as a pretty strong statement to say that it's very definitely not in our game plan that we're going to be in the bidding to make any corporate acquisitions nor to make any significant producing property acquisitions. In fact, year-to-date, we've made very minimal producing property acquisitions; I think about $6 million is all we've made on the producing property acquisition front. And it wouldn't surprise me if at the end of the year, we've only made perhaps $6 million at the end of the year of producing property acquisitions.

What we are seeing out there is a lot of companies are desperate to show production growth and they're willing to pay any price to acquire producing properties. And we're just not willing to get in that game. We see a very distinct differentiation in the reinvestment rate of return you can achieve organically versus the reinvestment rate of return that can be achieved by either buying producing properties or making corporate acquisitions.

And we believe that ultimately will show up -- as it works through the P&L statement, it will ultimately show up in companies' ROE and ROCE. And if you take a look at our ROE and ROCE over time, we think it shows up. So don't look for us to participate in any big deals.

Okay. Can I sneak one last one in or should I jump back in line?

No, go ahead.

Just with respect to your San Patricio success, can you give us a little more color on sort of the scale of the opportunity base?

In San Patricio County, yes, that's where we have the Kirk well. Yes, I think you can expect we're going to have considerably more successes to report in that area. That is where we drilled -- the Kirk well was a good for Frio well there that we reported it about 13 million a day and very high condensate yield.

And we've got a lot more prospects in that area. And pretty much, we'll have, I'd say one to three kind of [high-rate] wells every quarter for probably the next year or two, if we choose to put them in the press release. So I would say they won't be spectacular things that are going to carry the whole Company, but they're going to be wells that are going to help carry our Corpus Christi division very clearly. So we've got a pretty good inventory in that area.

Thank you, Mark.

Robert Morris from Banc of America.

Good morning, Mark. Question on the Barnett, cutting back on the number of rigs you have planned to have working by year end. Given the returns and the economics and the success you've had here, why not just go ahead and still go to 23 rigs and ramp production up even more and get those returns captured here near term rather than pushing them out?

Yes, we really are working on kind of a well count number. And like I say, the goal this year -- and really, it is in terms of ability to supervise things -- about 225 wells this year with the people we have is what we can say grace over if --.

And so what we have found is that the current backlog we have is ability to get wells completed. If you notice, where I highlighted that we have 100 wells drilled year-to-date and about 30 of those wells are either waiting on completion or waiting on pipeline tie-in; that is where our backlog is.

So what we've found out is we're drilling the wells faster than we can get them completed, if you will. And part of that is just due to our internal staff ability to supervise the myriad of fracs we have. And so we just decided that there is no sense running more rigs and building up bigger backlogs until we can get staffed up internally to handle even more fracs.

I guess bottom line is we can barely get frac this year of 225 wells. So one of our big challenges is really -- for next year is how are we going to double -- if we double the activity, how are we going to internally supervise the frac designs and everything for double that amount.

So it was really a decision of how many wells could we adequately supervise the well completions and production tie-ins of this year, not so much how many could we drill, if you will.

Okay. So you're still looking at 18 to 20 rigs next year is all?

Yes, I think that is what the -- what we will be doing basically, Bob, is -- and I guess the way to look at it is when we started this program, and even today, we had a rig fleet that is kind of like it was an original pickup rig fleet of what we could get our hands on to start this program. I'd say within a year from now, we're going to have a rig fleet that is a rig fleet that is fit for purpose.

And so most of the rigs that we originally picked up are not going to be ones we have, and it's going to be a fit for purpose rig fleet that's going to be able to move a lot more readily and able to be able to drill these wells, we think, a whole lot faster than the fleet we currently have.

So we think we're going to be able to show tremendous efficiency gains in 2007 for the entire fleet relative to, say, 2006 or 2005. And we've got the first of this new fleet in hand and we're drilling the second well with it. But we think that is going to be one of the big advantages we have, really (multiple speakers) forward.

Second question, on the Johnson County western wells, I noticed in your presentation you lowered the net reserves per well in your estimate for both the western and northeastern counties. What is that attributed to?

Yes. In the eastern counties, I would say the reserve estimate that we have now is probably a little bit more of, I would say, representative -- we now have a bigger population of wells and I believe we're showing at about 2.5 net Bcf now. So that is probably more representative of what the larger population is going to be.

It's mainly we drilled some really, really good wells early on and had a small population of wells there. And now I'd say probably 2.5 Bcf is more representative of what -- we drill hundreds and hundreds of wells there; that's kind of what I would expect it to be.

In the western side, what that is due to is we're drilling more short laterals as we get into issues about drilling a little bit closer to these kartsts and trying to -- as were having some lease obligation issues, we're having to drill more Class B and Class C locations, and we're not drilling all Class A locations.

So where the ultimate mix is going to turn out to be in Johnson County, I don't know -- it may go up a tenth or down a tenth. I think in the western side -- what did we do? Lowered it like a tenth of a Bcf, I think.

So for all of Johnson County, your total net potential is still 1.35 to 1.18. So you think you make up for that elsewhere?

Yes, I think so. We have actually -- for the two counties that we haven't drilled wells yet in, Palo Pinto and Hill County, we believe that those tow are going to turn out to be better than average counties too, just based on the seismic that we have. But until we drill wells there, we really can't say that for sure.

and those other counties, are you saying 0.8 to 1 or 0.8 to 1.4 Bcf per well?

The reason it's weighted up there, we believe that, like I say, Palo Pinto and Hill may weight the average up. That is why -- it's our belief that the Jack County and the Erath County and the Hood Counties are probably going to be 0.8 to 1 net. But it's also our belief that the Hill County and the Palo Pinto may turn out to be better than the Erath and the Palo Pinto and the Hood Counties.

Okay. Thanks, Mark.

Gil Yang with Citigroup.

Hi, Mark. Can you comment on the progress with the negotiations for Block 4(a), what -- to get the first production on schedule, how certain are you that you're going to get that and what needs to be done?

Gil, the negotiations for the new contract for Block 4(a) are currently in progress and we're very confident that we will be able to get a gas contract to bring those volumes on line. Mechanically, that should happen in 2009.

What we're negotiating about is the way to sell those volumes prior to that, some portion of it in '07, some portion of that in '08 -- kind of our excess volumes in other blocks, and then back it up with that contract with the actual volumes from 4(a) in '09. So I think negotiations are progressing nicely.

I'm sorry -- the volumes you would be able to commit some gas from your existing fields to supply the needs for the new contract before the production out of 4(a) is ready -- is that what you are saying?

That is our intent, yes. We are discussing that with the government right now.

So you have deliverability -- you have spare deliverability capacity out of the existing fields?

Yes. In our SECC block and in our UA block, we do have excess deliverability.

Can you characterize how much extra deliverability you have?

Actually, in the first half of the year, we were utilizing much of that excess deliverability to fill domestic and LNG contracts in country. So I think you've pretty well seen deliverabilities on a gross basis in the neighborhood of 0.5 Bcf a day.

Okay. We are seeing that. Mark or Lauren, I think Mark, you commented on the rates of return for some of these areas on a direct basis 30% to 60%. Can you comment on a full-cycle basis, if you factor in the land acquisition costs and seismic, etc., what the rate of return is?

Gil, before he gets to that, let me add on the Trinidad story there that we are going to be developing another field there called the Oilbird in the fourth quarter and through the first quarter of '07. So our deliverability will actually increase beyond that level.

Oilbird is what prospect?

Oilbird is the discovery we made about four years ago. It's mostly on the SEEC block and partially on the UB block.

Okay.

Gil, in relation to your comment or question there about full-cycle cost versus direct cost in the Barnett, the reason we addressed direct costs there are that the land costs and the seismic costs are all costs that we incurred -- generally, the land costs would have been incurred over the last two or three years as we accumulated our significant land position in the Barnett. And the seismic costs would have been incurred primarily last year as we shot most of that acreage.

If you included those costs in there, I'd say generally it would probably derate those rates of return I quoted by probably about 5%. And the reason it wouldn't derate it more than that is that one, the land costs were cheap relative to what the land prices are today. And two, your denominator is so big -- there are so many wells that we would anticipate drilling on the acreage that that on a per-well, the land and the seismic costs are quite low.

Okay. Mark, can I just go back a second to Oilbird? Is Oilbird a Lower Reverse L?

No, Gil, it is in the original block that we acquired back in 1992, the SECC block. There were a couple of old Texaco wells drilled back in the early '80s; they actually discovered a couple of sands that turned out to be the top of the accumulation. We found additional sands below that as well as fleshed out additional fault blocks.

So it's a new discovery -- an appraisal and new zone discovery that we made. And I can't recall the exact year, but it seems like it was about '99, 2000, something like that.

And do you have an estimate for the EUR?

I don't know, it's a couple hundred Bcf. But the Oilbird reserves are already reflected on our reserve books; they are shown there as PUD reserves. So all that will happen this year is those PUD reserves are going to get shifted to PDP reserves.

How much development capital for that?

I think the total is going to be around 150. Not all this year --.

I think probably this year, probably about $50 million, $60 million of our total CapEx budget is going to show up as money spent to develop to transfer those reserves.

And the rest next year?

We had some last year too.

Yes, some last year.

All right, thank you.

Joe Allman from JPMorgan.

Mark, could you give us an update on that West Texas Barnett shale well, the first horizontal one you had? I think it IP'd at 2.25. Could you kind of give us where that is now?

Yes, really no update on that, other then actually a slowness on there. We had -- the last quarter, just to update everybody, I mean we had reported that we slowed that well just a flair for about 90 days -- we were waiting on a pipeline -- and the flow results were encouraging in that it acted and have flow characteristics similar to a Western Johnson County kind of well.

And really, for the last 90 days, it has been shut in waiting on a pipeline connection. We had hoped that we would have a pipeline connection, frankly, by late July. And we've had just terrible right-of-way issues out there, and now it looks like it's probably going to be late November before we get that darn thing connected to sales. So there is really no news update there.

We are currently drilling a second well out there, a second horizontal well. And we will have that well completed, and probably it will be late November, early December before we're able to flow that well to sales. So unfortunately, our evaluation process out there is just slowed down due to extreme difficulties in getting a pipeline connection out there.

I guess that only good news is, if there's any good news, is that we haven't heard of anyone else out there in that whole area who's got any other well results out there. So things just are moving very, very slowly out there. But nothing adverse has happened; it is just we're kind of in suspended animation, frankly.

Okay. Helpful, Mark. Thank you.

(indiscernible) with Sentinel Asset Management.

On the rig side, are we experiencing any kind of shortage of rigs, upward pressure on the rig (indiscernible)?

No, we are getting all the rigs that we need at this point. The rig rates have continued to increase somewhat; they've been up about 8.5%, 10% since the start of the year. But they've flattened, it seems. But we've got a sufficient number of the rigs.

Okay. And for 2007, since you would be almost doubling the drilling program to 450 wells from 235 this year, you are not going to be facing any kind of shortage of rigs in '07 also?

No, we've contracted for new-build rigs and they are just starting to be delivered now. So we will be picking those up through the balance of this year and also into 2007.

Okay. On your hedging program, (indiscernible) oil edges, you mentioned 25%, 26% for 2007 your oil operation is hedged, or it's less than that?

No, no, it is much less than that. We have only 3000 barrels a day hedged for 2007 at an average price of $77.50.

And gas is only 4% hedged?

It is only 4% hedged, yes. So I would say we are very lightly hedged for calendar year 2007 in both commodities.

Which means that you're expecting strong gas prices for 2007. Is that because drilling or gas reserves in the U.S. are rising demand from that?

We're expecting fairly robust gas prices, mainly because we just haven't seen a supply response from the high level of drilling activity in the U.S. and Canada. So we believe that -- I guess we believe in what's called just reset theory, that November 1st you will have about 3.45 TCF of gas storage, and everything kind of resets. You won't have a storage overhang, and that gas to us looks like it will average in the range of about $9 in Mcf for calendar year 2007, kind of depending on what happens during the winter.

Okay. One last question on the tax rate. Obviously, you had some benefits in Canada and Alberta, and this is going to be continuing; this is going to be recurring kind of thing? Or you had that in 2003 also, and some quarters of '04. So this is a recurring thing that would lower your effective tax?

The answer to that question is mostly no. The three reductions -- or we actually get two reductions, Canada Federal, Canada Provincial in Alberta, and then you had an increase tax rate in Texas on their, what's known as a franchise tax, but it's becoming what's known as a margin tax.

So you obviously have to, when you have a change in the tax rate, that obviously causes deferred taxes to need to be recomputed, and that is what -- the reflection you have here in the second quarter. You will have, of course, the benefit of the now lower tax rate in Canada going forward, but they will not substantially lower our overall tax rate.

Okay, got you. Thanks a lot.

Joe Magner, Petrie Parkman.

Good morning, thanks. Just curious, you mentioned earlier your thoughts about benefits of organic production growth and maintaining a low debt balance. Just curious what your thoughts are in terms of optimal capital structure. Net debt to cap is only running around 3% to 4%. You've got in excess of $700 million on your balance sheet.

It looks like, obviously depending on what happens with gas prices, but it looks like you should have enough cash flow generated internally to fund this year's budget and next year's, if it's in the same range as this year. Just kind of thoughts about optimal capital structure and any plans for that cash balance just sitting there?

You think we might be little undergeared, Joe?

It appears to be at this point.

Yes, the reason that we are running such an underlevered balance sheet is really twofold. One, we're still frankly trying to assess what is the proper level of number of wells that we need to be drilling over the next four or five years in the Fort Worth Barnett. Is 400 or 500 wells per year the correct number or is it more than that? And frankly, we just don't know yet; it is too soon to tell.

And then the second thing is on these other six incremental Barnett clone plays, we're really waiting to see whether those plays are going to work or not. Obviously, if those plays work, they are all going to need some funding as we get into 2007 and probably 2008 before they become self-funding. And so we are keeping a very light balance sheet on the hopes that we have a success case there and we have to fund several of these plays from scratch, in addition to keeping all of the other projects going.

So until we get some clarity on how these six Barnett clones turn out, we're probably going to keep a pretty light balance sheet. Obviously, if we are unsuccessful and all the clones turn out to be drones, then we will look at some other uses for that capital. We're not going to permanently run a balance sheet that is that light. And one possible use may be share buybacks if the clones don't work.

Okay, so -- fair enough. And then on another note, back to the natural gas markets, you mentioned on the first-quarter conference call the possibility of maybe facing some involuntary shut-in productions as gas storage builds here over the balance of the season. Obviously, things have changed here in the last capital of weeks. But have you seen any of that yet and are you still expecting to see any of that sort of activity over the next couple of months?

No, we have not seen any of it yet. And I guess our assessment of it now is that we're now down to where the possibility of that occurring, I think, would only be in one month, and that might be October. And I think if we get a sustained weather run here in August, I think the likelihood of that is beginning to drop significantly. So I think the probability of having a serious production (technical difficulty) is considerably lower than we had at last earnings call.

Okay, great. That's all I've got. Thanks.

Irene Haas from CanAccord Adams.

This is my question, going back to the whole clone versus drone issue. Mark, I want to ask you a very general question. I mean there's obviously a lot of this shale gas all over the U.S., especially for the Devonian and Mississippian. Once you have decided an area that the shale would work -- i.e., it's got the right organic matter that is generating gas as such and it would react to frac -- can you tell us just in a very broad term what are the key challenges to bring it to commerciality?

And second question, sort of related to that, is there have been some pretty ancient shale gas production out in Appalachia. Can you give us a little color as to why we are not seeing a whole lot of action on the eastern part of the U.S.?

Yes. Let me Loren address that.

Commerciality in these remaining fractured shale rocks around the country are really case-by-case. How deep is it, how hard are the rocks above it, well cost, completion costs are a primary driver. Because in most cases, it's reserves per well that are going to determine the economics on that thing, and drilling costs are quite variable.

Also in Appalachia, I think you are seeing a slowness there for several reasons. One, the cost in Appalachia because of the logistics issues, pipeline issues, are more extreme than they are in normal operating environments. We are kind of looking at that area, as are a number of other players. And obviously, there has been shale gas production in Appalachia in the past, so it can be economic.

As these costs escalate, rig costs, completion costs, pipeline costs escalate, some of these plays are going to be priced out of the market, at least for now.

We currently have, as Mark said, six plays that we're actively hoping to decision this year. We have another bank of half a dozen or so plays we're working on for next year, and decent acreage positions in all.

And you mentioned three of the parameters that we look for. There are probably about three others that we look for that we'd rather not comment on publicly. So our opinion is that more shale plays will work, but not all the shale plays will work.

Thank you; that is good.

David Heikkinen from Pickering Energy.

Good morning. Just going through non-Barnett questions and looking at ranking the six different areas that you show additional growth, if you were thinking about total production in each of those regions -- you mentioned the Rockies growing in the low double digits -- could you prioritize where you see the most growth coming from out of Rockies, East Texas, Canada, South Texas, Mid-Continent and then New Mexico, West Texas? Where should we really focus?

Yes, I guess -- I may not get it in the correct seriatim, but just off the top of my head, in the domestic side, over the next two or three years -- taking it out say through 2008, David -- I think we can continue to expect that the Rockies -- this year, we're expecting roughly 13% year-over-year growth. And I would say 2007 and 2008, we can expect some kind of double-digit growth out of the Rockies each year.

So that is going to be continued and pretty steady. And a big driver of that is going to come out of our development in the area of Utah in our Chapita Wells, the Natural Buttes area, which is primarily that Mesaverde development in Utah.

In the South Texas area this year, we're expecting about 6% year-over-year growth. And I would say we have a pretty fair chance of sustaining somewhere in the range of a 6% production growth there year-over-year. And both these are very large division for us.

South Texas is about 180 million a day? In rough numbers?

It's about 200 million a day, actually. And then our East Texas -- or our Tyler division -- East Texas/North Louisiana -- that is an area that we had counted on for pretty dramatic growth this year; I think it was about 9% this year. But that one, the growth isn't going to be as high as we thought, mainly because we are having to wait really until likely the first of the year before we get our East Branton Field tied into for some downstream processing.

The advantage of that is that we're probably going to have very dramatic growth there in 2007 versus 2006. And as we look out, I'd say '07, '08 are going to both be pretty strong years coming out of that. So that I would rank as probably the third most powerful division. And probably in percentage terms, where going to have pretty powerful growth there year-over-year '07 versus '06.

And the other areas, our West Texas division and our Mid-Continent division, we're probably not going to have nearly as impressive percentage gross over the next two or three years. We will be lucky to have more moderate production growth there, perhaps 3% or 4% a year there.

And the Gulf of Mexico, it's just really in our opinion it may have pretty decent production growth next year year-over-year only because it's basically been severely curtailed this year. If we ever get the infrastructure issues resolved. But long-term for us, we're basically -- that is just a winding down exercise. We are not going to sell it, but it's just going to produce itself out basically for us.

Okay.

So that is just a rough hierarchy.

Outside of Gulf of Mexico and East Texas second half gas growth in U.S. is pretty big. How much do you have behind pipe awaiting hookup or what level of confidence as far as the range of second half '06 production in the U.S.? What key indications are there to drive you to the high end versus the low end? First, how much is behind pipe; and then second, where is the fling factor?

Yes, the 8-K if you look at it, basically is projecting that we're going to have pretty high rampup in domestic production growth in the third quarter and in the fourth quarter. And where we've got the second half production growth projected, I mentioned in Oklahoma there, we've got about 15 million a day that's going to be coming online pretty quickly from that division.

We've got, as we mentioned, about 30 wells currently in the Fort Worth Barnett that are just waiting on pipeline and/or completion. And that backlog -- actually that will accelerate in terms of the amount of production. As we add rigs and in the Barnett during the second half of the year, we expect that production to ramp up pretty dramatically from the 140 million a day as we go through the second half.

We also expect South Texas to ramp up and the Tyler division to ramp up. And then very predictably, we expect our Rocky Mountain prediction to ramp up as we been adding rigs there steadily.

So it's a pretty predictable and fairly uniform contribution. But the big contribution or a significant amount of that contribution is going to be coming from Fort Worth.

Okay. And just one final question, as you move further to the West in the Fort Worth Barnett shale, gathering and firm transportation availability, can you talk some about what's going on with that?

In Jack, Hood and Erath, it is currently available; in Palo Pinto and Hill, it is currently not available. And that is why we haven't drilled any wells there yet. It will be available in 2007. So I'd say it's still -- even in those counties where it is available, it sometimes takes us 90, 120 days to get a well connected just because it's not widespread availability. [There's never] any real underlying production infrastructure out there, so it's almost a build-as-you-go kind of thing.

Okay, that's feasible. Thanks, Mark.

John Herrlin of Merrill Lynch.

Mark, just some quick ones. For East Texas, the East Branton Field, is that Cotton Valley?

It's actually a lime underneath the Cotton Valley. If you call it Cotton Valley Lime, that is fine.

Barnett Shale, regarding your spud to tie-in times, you've talked about pipeline or gathering issues and fracs. Which takes the longest and what has happened over time in terms of the spud to tie-in times between when you drill the well and when you actually hook it up? How has that increased?

Yes, I guess what's -- right now what's taking the longest time is really the time from when you move the drilling rig off it to when you get a well connected to sales. And one of the things that's kind of -- you have to factor there is in Johnson County, what we do it is we do these kind of fracaramas.

In other words, when we're drilling these wells on 500-foot spacing, each well interferes with another. So what we do right now is we will drill four or five wells 500 foot apart and we'll keep all of them shut in and frac all of them one after another. And then we will bring on four or five wells simultaneously.

But what that does is, for example, the first well that you drilled, you may not bring that well on for, say, two to three months since you drilled it, because you are waiting until you drill the second, third and fourth wells and then you frac them all together.

So logistics are still -- it's a whole lot more complex, John, than anywhere else we've ever worked, other than offshore, in terms of time to get things connected there.

Well, on average, how many days is it running then?

Gary is guessing here, looking at me, 45 to 60 days per well, I guess -- from when you'd move the drilling rig off to when you get it connected to sales.

That is fine. You didn't comment on price basis differentials. It looked to me like you did a little bit better this quarter on natural gas. What are you seeing happen in the market?

You got me. I guess what -- if we have done a little better, it's just that we may have -- versus our 8-K, it may be that we just had too wide a differentials in our 8-K. I'm not sure that we've seen anything other than if the market get tighter, it seems to us like the differentials sometimes get a little bit tighter, John. But don't have any real good explanation on that.

Okay. Last one for me. What do you think your overall decline rate is for the Company as a whole right now?

Probably, it's -- for the entire Company, for the domestic part of it, John, I still say it's probably in a range of 25 to 30%. It is not far off from what we believe the average for total U.S. is. I know most people get asked -- when they are asked that question, they say, well, we believe the total decline of the U.S. is this, but our company has much lower decline rate. We don't really subscribe to that theory. We think ours is not a whole lot different than the average, really.

That is it for me. Thank you.

Richard Moorman from Capital One Southcoast.

Good morning, gentlemen. I just wanted to ask a couple of things around Wolfcamp. You mentioned you had two very good rates there, a 4 million and a 6 million a day. Just wondering, would you put that down to having hit a sweet spot in the rock or would you credit your techniques or something you've done different in the drilling or completion of these wells?

Really, it's us continuing to work on our completion there. And over the last six wells, really, we've averaged somewhere close to 4 million a day, and that's up from our previous well completion that probably, averaged out to about 2.5 million a day.

That's very impressive. With the improvements of (indiscernible), would you expect the decline curve to be fairly comparable and will we be talking then about 3 to 4 Bcf wells potentially?

Yes, it's probably a little early to tell. We've just done this, as Mark was saying, over the last half dozen wells. We probably need to see a little bit more production. But it's going to probably similar to what we had on decline after three months' production.

Okay, super. And then just a last question. I know we've talked a lot about U.S. shale potential. One of my backgrounds was on the Canadian side, and there is always a lot of talk about the potential there. I'm wondering what EOG's thoughts are. Do you see -- although I know your base has been mostly shallower gas up there, do you see the potential for shale gas in Canada?

The answer to that is yes. In fact, one of six stealth shale plays and Barnett clones, one of those six is indeed in Canada.

Good luck with everything here. Thanks, guys. I appreciate it.

Monroe Helm with CM Energy Partners.

Congratulations on continuing to have the best organic growth in the industry. Most of my questions have been answered. But since this issue of takeaway capacity has come up, in the core -- your core part of the Barnett Shale in Johnson County is the -- are the gathering and processing systems in place for your production rampup in 2007, and do you have all that contracted at this point in time?

Yes, we do, Monroe. For the stuff in Johnson County, we are in good shape. We don't anticipate any problems for our rampup for '07, '08 and '09 that we expect in Johnson County.

Okay. One other quick question. Can you share with us what you are seeing differently on the seismic in Palo Pinto and Hill Counties and what you see in maybe Jack, Parker, Hood, Erath Counties?

Really, I think in the Western Ares in general we're seeing less karsting, less sinkholes, fewer geologic problems than we saw at least in parts of Johnson County. And that is kind of a hit-and-miss deal. There are parts of those counties that are more sinkholes and parts that are less. And I think statistically, we're just doing pretty well on the acreage we have.

In Palo Pinto and Hill, I think it's also a bit of a thickness issue. We see a little bit better thickness there.

Okay, thank you for your comments.

Ray Deacon with BMO Capital Markets.

Hey, Mark. I was wondering if you could talk about what you would attribute the decrease in the drilling times to in the Barnett.

I would say, simply put, practice. One thing we are real good at as a Company is give us a couple hundred wells to drill that are all pretty similar wells and we get real good at it. And that is pretty much where we are at in the Barnett. So give us another six months there -- well, really, give us until the November analyst conference and you're going to see some pretty, I think, impressive drilling time results in terms of days to total depth, relative to what we were doing just a year ago there.

It's bit selection, it's hydraulics, it's type of rig, kind of a standard thanks. But I think as far as drilling, if these things were straight holed, we'd be drilling them in four or five days, just to put it in context. The same holes that a year ago we were drilling in 15 days if they were straight holes.

You are seeing that kind of order of magnitude difference. Now there are obviously horizontal wells, so you're going to be looking at wells in the Western side that we will be drilling in 10 days versus wells that a year ago were taking us days. That is the kind of order of magnitude difference that where going to be showing you.

Got it. Thanks a lot.

Ken Carroll with Johnson Rice.

How are you doing? I know 2006 is looking a little tight in the North Sea in terms of any more drilling activity this year. How are you looking at '07; what are the plans are up there?

Unfortunately --

Is that going to continue?

As far as the rigs. it's looking equally tight and equally expensive. I would say right now, we may get one well drilled in 2007, maybe two wells drilled. And what we're looking at for 2007 are literally just rig windows. We're out in the market now shopping for people who have rigs contracted in the North Sea and saying, have you got a window where we can borrow your rig for one well. And it's going to be expensive.

But we have at least one what we think is a good prospect and hopefully two viable drilling prospects. It's just a matter can we get a window on a rig.

Got you. But that well will be more on the exploratory side than the development side?

Yes.

Great. Thanks, guys.

It appears there are no further questions at this time. Mr. Papa, I would like to turn the conference back over to you for any additional or closing remarks.

Okay. I want to thank everyone for staying with us here. And I would like to request everyone that they do kind of mark their calendars for those dates in late November for our analyst conference. We think we will have some pretty impressive things to show you at that time. Thank you very much.

And that does conclude today's conference. We thank you for your participation.