EOG Resources Inc (EOG) 2002 Q3 法說會逐字稿

Please stand by.

Good day, everyone, and welcome to the EOG Resources third quarter 2002 earnings 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 on the call.

Yesterday afternoon we announced third quarter 2002 earnings and cash flow results. We hope everyone has seen the press release.

This conference call includes forward-looking statements and oil and gas reserve comments. The risks associated with forward-looking statements and oil and gas reserve comments have been outlined in the earnings release, 10-K, and other EOG SEC filings, and we incorporate those by reference for this call.

With me this morning are Ed Sagner, our President and Chief of Staff; Loren Leiker, our EVP of Exploration and Exploitation; Gary Thomas of EVP of Operations; and Maura Baldwin (ph), our Vice President of Investor Relations.

We're pleased with our consistent operational and financial performance in the third quarter when we had to circumvent some gas price challenges in the Rockies and (ph) Canada. As outlined in our press release, during the third quarter, EOG reported net income available to common of 26.1 million or 22 cents per share.

To convert reported earnings to reflect actual cash paid out and eliminate the mark-to-market loss on our normal and previously disclosed gas hedges, the following adjustments can be made to conform to most analysts' practices of matching realizations to the settlement month. Add back the $7.8 million loss for the mark-to-market impact of our outstanding futures transactions, which is 5.1 million after tax or four cents per share; subtract the 2.9 million -- 1.9 million after tax or one cent per share of actual cash paid out during the quarter to settle commodity contracts.

Adjusting for these items, net income available to common for the quarter was $29.3 million or 25 cents per share versus last year of $49 million or 42 cents per share on a similarly adjusted basis.

For the third quarter, discretionary cash flow available to common was $208.6 million or $1.78 per share.

I'll now provide some highlights regarding our diverse operational activities. In South Texas, we made good progress in our workhorse (inaudible) play and also in our emerging (inaudible) play. However, our most discrete project in South Texas is the Dinn Ranch 16,000-foot deep Wilcox (ph) play. During the quarter, we completed two additional wells -- the Buck Hamilton Number Seven (ph) is currently flowing 21.6 million cubic feet a day and the Hamilton Encinos Number One (ph) is flowing 9.6 million cubic feet a day. We have a 65 percent and 100 percent working interest respectively in these wells.

In early October, we installed additional surface processing facilities to remove carbon dioxide, and our net production increased from 17 to 35 million cubic feet a day. We expect year-end exit rates of about 42 million cubic feet per day from this area.

In the Mid-Continent Division, we've continued to have good results with our Texas County, Oklahoma program. We recently completed the Mason 23 Number One (ph) at five million cubic feet a day and the Northwest Freeman 30 Number One (ph) at six million cubic feet a day. Both are 100 percent working interest wells and are 7,000 foot deep (inaudible) completions.

In our West Texas horizontal Devonian play, we're very excited about our most recent completion, the Noki II (ph) number 1402H (ph). This dual lateral well is currently flowing eight million cubic feet a day, which is our best well to date. We've got five rigs running in this play and we expect to see meaningful production growth in West Texas by year-end.

In the Rockies, our Utah bigger target Mesa Verde (ph) program continues to yield good results. Six out of seven of these tests have been successful. Typical reserves are about 1.3 bcf per well for about a $1 million well cost.

In Canada, our third quarter volumes were 23 percent higher than last year. With additional well connects relating to our shallow program, where we will drill approximately 1,000 wells this year, we expect to achieve a year-end exit rate of about 165 million cubic feet a day.

In Trinidad, production increased due to the start up of the C&C (ph) ammonia plant. We now have two different traunches (ph) of gas sales. Roughly 115 million cubic feet a day from our SECC (ph) block, which goes into the Trinidad indigenous market and 47 million cubic feet a day, which is feedstock for the C&C (ph) ammonia plant.

During the quarter, we achieved two significant milestones. We extended our SECC (ph) concession through 2029. This now gives us the ability to secure longer-term incremental gas markets. Additionally, we added the 97,000-acre UB exploration block. This block is in the same fairway with our existing SECC (ph), UA and lower reverse L blocks and allows us to apply a regional geologic mileage to additional acreage.

We will operate and have a 55 percent working interest in this block. We now have an array of exploration projects in a gas rich fairway and our -- job during the next 12 months in Trinidad is to find additional reserves and develop additional profitable markets that will allow us to accelerate and extend the 11 percent compound annual production growth rate we have in hand through 2006.

I'll now turn it over to Ed Sagner (ph) to review cap ex and capital structure.

Thank you Mark.

For capital expenditures, total expiration development capital expenditures during the quarter were $211 million including 4.7 million of acquisitions. Capital expenditures year-to-date on the exploration development side are 615 million, which includes 49 million of acquisitions and as you are aware completed acquisitions year-to-date have been focused on adding to our shallow GAAP acreage position in Canada.

In addition, to the 615 million that I mentioned, year-to-date we have spent approximately $15 million on equity investments related to the C&C and Nitro 2000 (ph) ammonia projects in Trinidad and as you are aware, the C&C (ph) project is now fully operational.

Capitalized interest for the quarter was 2.4 million. Interest expense increased for the quarter reflecting the higher absolute debt level and one-time close out fees associated with the completion of our Section 29 type gas fee and financing that we began several years ago.

Cap ex for 2002, is forecast to be in the range of $750 million to $800 million excluding acquisitions. For 2003, our preliminary estimate given current gas prices for capital expenditures is between 800 and 900 million, once again, excluding acquisitions. Given the current 2003 strip, which is just under $4.10, we would expect to generate free cash flow in 2003 and would look to either pay down debt, buy back shares, or do both.

As to capital structure, at September 30th, total debt outstanding was $1091 billion. The debt-to-total capitalization ratio was 39.6 percent. Although our debt has increased since year-end 2001, we remain with the highest coverage ratio, the peer group and one of the lowest debt-to-total cap ratios in the peer group.

During the quarter, we re-purchased 700,000 shares at an average price of $34.70. As we stated at the beginning of the year, our goal is to maintain a flat share count. The share re-purchases year-to-date have offset employee stock option exercises that have occurred throughout the year.

The effective tax rate for the quarter was 32.6 percent. You'll also note that the deferred ratio was 247 percent, which essentially reflected our decision to expense IDCs rather than to capitalize IDCs on the current year tax return and at this point I'll turn it back to Mark to discuss marketing and hedging.

Thanks Ed.

I'll give you our thoughts regarding the North American gas macro and then discuss our hedging strategy. Simply put, we continue to see a supply challenge situation. We expect third quarter domestic gas year-over-year comps for all public companies to be down about six percent excluding any hurricane effects. This probable domestic gas production will be down five to six percent this year and we expect it to fall another two to four percent next year, even if we have a robust gas drilling recovery.

We expect 2003 Canadian imports to be down about half a bcf a day compared to '02, largely offsetting an L&G (ph) import increase of about eighty-tenths a bcf a day compared to '02.

In total, we expect the U.S. markets will have to make do with about two bcf a day less supply in 2003 versus 2002 and the price consequences of this are reflected in the futures market.

EOG is currently un-hedged (ph) regarding 2003 gas and we have 1,000 barrels a day of 2003 oil hedged at an average price of $25.89 a barrel.

Updated guidance for detailed modeling was provided in yesterday's 8-K. Regarding fourth quarter 2002 natural gas hedges, in October we were 35 percent hedged financially at about 3.23 and in November and December we are nine percent hedged at 3.35. Based on September 30th prices, we would expect a cash realized loss on these hedges of $9.9 million in the fourth quarter. This has been reflected in the third quarter earnings via the market-to-market adjustment but not in cash flow until the actual outflow occurs.

In summary, our game plan is to achieve a strong North American gas year-end exit rate that sculpts our products consistent with rising gas prices. Combined with our in-hand Trinidad production ramp up, we expect to achieve a 2003 total company production growth rate of six to seven percent on an absolute basis.

In 2002, we made a conscious decision to out spend our cash flow. During 2003, we'll be very watchful of service cost escalation and may well under spend cash flow and use the free cash to either pay down debt or buy back shares.

That concludes our formal discussion of our third quarter earnings and we'll open it up now for Q&A.

Thank you.

The question-and-answer session will be conducted electronically. If you would like to ask a question, please press star, one on your touch-tone keypad. In order for your signal to reach us, please make sure if you're joining us using a speakerphone that your mute function is turned off. Once again that is star, one to ask a question. We'll pause for just a moment to assemble our roster.

And our first question comes from Ellen Hannin (ph) with Bear Sterns (ph).

Thank you, good morning. I just had a couple questions. Mark one for you on the kind of the macro outlook. Can you, given us kind of a nice (ph) overview of what you think the supply situation's like, what it will look like. Do you have any thoughts on the demand picture?

Yes Ellen (ph). Number one we don't purport to be experts on the demand side, but generally, you know, our thought is, you know, U.S. supply is heading rapidly from 52 BCS (ph) a day, where it was last year, and it's by next year it's going to be about 47 BCS (ph) a day, so we're going to basically vaporize to use upon five BCS (ph) a day of supply out of our system.

And the demand consequences for that are such that in my opinion we're going to have to firmly (ph) price out about two BCS (ph) a day in investor (ph) of demand in '03 versus '02 and, you know, our best guess is that that equates to a gas price range between 350 and 450 in MCS (ph). And you know, right now we're at a strip of about 410 or so, so I would say that, you know, the futures market to me is probably fairly representing what likely will happen next year.

But the question of how much demand gets priced out and at what price level is one that, you know, we're not really comfortable in getting a specific answer because we really haven't got enough demand expertise to do a time (ph) on that.

OK. That's fair. Just another quick question for Ed. On your change in your assumptions on calculating expensing IDCs (ph) as opposed to capitalizing for tax purposes. Just curious as to why you wouldn't have made that selection last year when commodity prices were so much higher?

The answer to that, it is a year to year election, Ellen (ph), and as we planned for this year we didn't anticipate having enough taxable income.

OK.

And as it's turned out we do believe we will, and that also enables us quite frankly to go back and basically record it as an NOL (ph) and actually get a tax refund.

And is that tax refund a cash refund?

Yes it is. We will receive that sometime during 2002, probably in the latter part.

2003.

I'm sorry, thank you, 2003, probably in the latter part. We also did receive, or will shortly be receiving a smaller tax refund for our 2001 tax refund this year.

Great, thanks very much.

Moving on we'll take a question from Shawn Reynolds (ph) with Petrie Partment (ph).

Morning.

Morning, Shawn (ph).

Morning.

It seems to me like you have kind of consistently set your dry hull (ph) expiration (ph) expense impairment cost pretty high and you come in underneath it pretty regularly. Any comments on that and how we should continue to look at that going forward?

I think the best explanation on that, and let Lauren (ph) chime in if he'd like to, but quite frankly, it's mostly slippage in drilling schedule on specific wells. We also, in terms of forecasting, we normally assume that our Wildcat (ph) wells will be dry. And obviously that doesn't always happen, and so we get the benefit of that.

Particularly, I'd say on the high cost, you know, the high risk award wells, that's normally the way we try to budget them.

OK. Great. Thanks. That's all I had.

First Albany's Bob Christianson (ph) has our next question.

Yes, just if I may, some well updates on some of the things you said at your analyst conference. West Texas Divonium-Clay (ph) you were completing a well, a five-mile-step-out-slaughter-28-1 (ph). How'd that well turn out?

Bob, we're still testing on that well, and we'd really prefer not to add additional comments to what we said at the analyst meeting for competitive reasons. As you know, it's a pretty significant well for determining what the boundaries of that pool are, and we do have competitive activity out there right now.

Second question I guess, the Barnett Shale (ph), any when will you spud (ph) your first well, and I guess the second question is if you haven't, when do you what is industry having in the way of results around the immediate area?

Bob, we've not spud (ph) that well yet. In fact, we're going out next week to shoot some swath 2-D seismic to pick several locations, and really anticipating something probably in the first quarter, maybe one or two wells there. Our information is that industry is having a pretty good success both north of us and in between our two acreage blocks in terms of IPs, or initial potentials. We don't really know how those wells are going to turn out longer term, and that's where the risk remaining on the play in that area.

And last one, if I may. On the Murnah-Anacline (ph), I head that Williams (ph) was building a 35-mile pipeline up to that well. Is that is that true, or what do we know any more about that well that you were going to offset up there?

No, we hear the same things, Bob. We've not had a report yet on the completion of that well, but we understand that it's moving in that direction. We are still hoping to get a 3-D shot in that area in the fourth quarter, although we are having some permitting delays and would hope to spud (ph) a well there sometime in the first quarter.

Thank you. Bye, Lauren (ph).

You're welcome. Thanks, Bob (ph).

Irene Hoss (ph) with Sanders Morris Harris (ph), please go ahead.

... express your view on the gas side. I notice you put on some oil hedges. Can you give us a little color on how you look at oil prices for 2003?

Yes, good morning, Irene (ph). Yes, on our view on the oil side is I guess that there is a fair likelihood that over the next two or three months we may lay on some more oil hedges for 2003. You know, it's a real wild card, but I guess we would subscribe to the theory that if in fact the regime change in Iraq did happen, that there would probably be some downward pressure on oil prices. So I would say as you kind of look at our strategy as we go to '03 on the oil side, we're more likely to end up with a higher percentage hedge.

On the gas side we're watching it very closely. I mean, 410 is obviously a pretty tempting price. It is pretty certain though if we put gas hedges on, we would put collars instead of just the, you know, fixed price swaps. And the collars might be roughly maybe 50 cents up and 50 cents down from the strip price, but at this time, we're still, you know, we think that the as you get the production data coming out, all public companies, and you see what the year-to-year comps are, you and get some of these weather comps through October and November, you'll still see a bully- sammin (ph) we would believe on the on the gas futures market.

Thanks thank you.

And we have a question from Andrew Leeds (ph) with RBC Capital Markets.

Morning, guys. I was wondering I know it's still general or broad, but of your eight or $900 million of cap ex, could you kind of go through U.S., Canada, Trinidad, other?

We really haven't done a lot of breaking out of that. I don't know that at this point that the percentages would be that dramatically different than we've employed them this year.

What were those, then?

And if I can help you with that ...

That would be helpful.

We have spent approximately or are expecting to spend in the range of 50, 55 million internationally, and we have spent a little bit more than that in Canada, excluding acquisitions.

Right (ph). Thanks.

Jeff Mobely (ph) with Raymond James has a question.

Hi. Several of my questions have already been asked, but I did have a question regarding the benefit of your physical swaps in the Rockies as well as what your viewpoint is on the future Rocky Mountain basis differentials going forward.

Yes, in terms of our situation in the Rockies, we've got the we really haven't been hit very hard by this huge basis boil-out (ph) up there in that we have firm transportation on a pipeline that takes the majority of our gas to a mid- continent area. So we been able to exit most of it to the mid-continent and get those prices. We have had about 10 to 15 million a day that is subject to the vagaries of, you know, of Rocky Mountain pricing up there, and we moderated some production in the third quarter relating to that and also done the a few term deals to try and ameliorate that situation.

Our view of that basis is that there's probably 100, maybe 200 million a day of gas backed up in the Rockies now relative to the pipeline takeaways. That will certainly be eliminated next May when Kern River (ph) expansion gets done. But historically, that basin has tightened up in the in the winter in the Rockies as you got localized demand just due to heating demand there.

So if we had to guess, we would guess that probably starting in November, you'll see that basin basis tighten up, and that probably by May, it'll pretty much go back to normal Rocky Mountain levels.

Great. Thank you.

OK.

If you find your question has been asked and answered, you can remove yourself from the queue by simply pressing the pound symbol. Frank Bracken (ph) with Jeffries and Company (ph) is next.

I was hoping you could help me out with some math on your gas revenues. If I took the 946 million a day that you did, multiplied it by 92, that gets me 86 7 bcf, and I multiply it by your reported price, I get 237 an of an mcf. I get $206 million. That pales in comparison to the 224 you reported. Can you help me reconcile the gap?

Yes. That gap, the great bulk of it comes from the essentially basis gains that we have.

OK. So the you're not expressing your basis gains in your reported pricing.

That is correct.

OK. Thanks.

David Heikenen (ph) with Hibernia South Coast (ph) has our next question.

Just a quick question. At the analyst meeting you talked some about some of the desorption of Canadian coal bed methane. Do you have any thoughts as far as your '03 pilot plans?

David, we are continuing to desorb those cores, and what I can say that so far it looks like our gas contents are very similar to what we think is happening on the on the block in between our two bookend blocks, as we reported at the analyst meeting. So I'd say the desorption is all very positive so far. We would hope to do pilot work in '03.

On both the north and the south?

I can't really say that. I would say, you know, one of those looks better than the other to us, but really, we're further along on the north side than on ...

OK.

... the (ph) ...

OK. Thanks a lot.

As a reminder, if you would like to ask a question today, please press star, one on your touch-tone keypad. And J.P. Morgan's Shannon Milm (ph) has a question.

Thanks. Good morning. Mark, to your earlier comment, I'm just trying to get a sense as to where oil service cost pressures really begin to crop up in earnest. And if I just take, you know, your indicative cap ex increase, let's call it seven to 12 percent in 2003, I mean, it's and that that's actually not totally inconsistent with what our forecasts are for '03 on a broader basis. Is it safe to assume that your rig count goes up sort of proportionally, and if that is, you know, a leap we can make, that would imply something close to an 800 gas rig count for the industry next year.

So my question is first, how errant is that math? And secondly, if it is on target, at what gas price rig level do you think or sorry gas rig drilling level do you think oil service cost really comes into play? Where are we going to hit resistance?

Yes, I think, Shannon, it is, I mean, your assumption is right that we would expect to be running more rigs next year than this year, and, you know, maybe a 12 percent or so increase is about correct there. We've been consistently surprised at the very low level of drilling response here due to these pretty strong prices. So there's obviously a disconnect there, and I still think the main reason for that disconnect is that just a lack of viable drilling prospects by the industry of quality drilling prospects.

My sense as to where we see some real price pressures on us probably is when the gas rig count gets to 900 and starts getting worse (ph) to 900. And the comment we made about though we're going to watch service costs and really efficiencies very closely is that as we post-audited our 2001 experience, when everybody got caught up in a drilling frenzy, there are just a lot of scars that we have in terms of deterioration of service company efficiency, deterioration of our supervision efficiency, and cost escalation, and we've pretty much resolved, as a management team that no matter what happens next year, we're going to try and mitigate those kind of circumstances at BOG (ph), even if it means scaling back our drilling activity if inefficiencies start getting really biting on us.

Yes. Right. OK. That makes sense. Thank you.

OK.

We'll now go to Brad Yago (ph) with Credit Leonase Securities (ph).

Thanks. Good morning, guys. Couple of quick questions. Mark, you may have said this already, and I missed it, but what production volumes did you see impacted by the hurricane, did you lose during the third quarter?

Yes, morning, Brad. If you take a total U.S. production level of roughly 630, only about we only produce about 60 million a day out of that total in the Gulf of Mexico. And so the effect we had related to that hurricane was pretty small, maybe about two million a day or something, if you put it on a quarterly basis.

OK. And in looking in particular at U.S. liquid volumes, they're up pretty significantly over the last couple of quarters, about 10 percent down from the first quarter. Can you tell me what you think for the for the remainder of the year and where the where the main part of that decline has come from?

Yes, Brad. And you're talking about U.S. crude volumes primarily?

Yes.

Yes. Yes, what we're seeing in U.S. crude volumes are that in a couple areas we'd really scaled back our activity level. One is in the North Shafter (ph) area in terms of, you know, we really slowed down our drilling out there in California. We pretty much had the limits of that field defined. Also out in the West Texas area, where we've done a lot of oil related drilling the last couple years, we pretty much have scaled back that, mainly because the, you know, we drilled pretty much the prospects that we had out there.

So as we as we move into the fourth quarter and into next year, I don't think you're going to see continued declines, but on the other hand, I would expect that, you know, we're not looking at rapid ramp ups in our oil production activities over the next five or six quarters.

OK. One other quick question, if I can. To follow up on Frank's question, when you included the basis gains in your realized third quarter gas price, are you saying that you closed out future basis contracts and took the gains currently, or are you just talking about the basis improvement that you got through your existing contracts?

No, that's a good question, Brad. We actually hold long distance pipeline capacity, particularly in the west, going out. And we normally see, you know, minimal fluctuations in value having holding that capacity. But in this particular quarter, given the basis blowout in the west, obviously, being a holder of firm capacity going out was an advantage.

OK. So I'm still not clear why that didn't show up in just your realized price.

Because it wasn't a well head at the well head.

OK. All right. OK. Thanks guys.

Yes, Brad, just to clarify, I mean, we don't have any financial basis hedges at all in the company right now, and we've historically not been a basis hedger on financial markets.

We'll now take a question from Siniel Swamee (ph) with Delphi Management (ph).

Hi. Maybe I'm missing this on your release, but have you what are your proved reserves as of the end of the quarter?

Well, we don't report quarterly reserves ...

OK.

... so, you know, the only thing we could quote you is proved reserves as of January 1st, which were approximately 4.2 tcfe on total company.

And where do you expect to be at the end of the year?

In terms of reserve replacement, we haven't given any specific numbers, but what we can say is that if you look at Trinidad, we had a very large discovery in the first quarter of this year, so our international reserve replacement will be very, very good. If you look historically at North America, pretty much year in, year out, we've averaged between 130 and 150 percent reserve replacement, so ...

OK.

... I would say it would be in that range in North America. The overall company number will be bigger than that, skewed by the large discovery in Trinidad.

OK.

Thanks (ph).

Thank you.

And that is all the time that we have for questions today. Mr. Papa, I would like to turn the call back over to you for any final and closing remarks.

OK. I want to thank everyone for listening in on the call and remind everyone that the replay of the call will be available on the EOG Web site. We are very, very excited about where we're going at EOG. I think that the fact that we're 74 percent North American gas that our production base is exactly the sweet spot where we want to be, and look forward to having a very interesting fourth quarter and also 2003. Thank you.

Once again, thank you everyone for joining us today. That does conclude today's presentation.