EOG Resources Inc (EOG) 2002 Q4 法說會逐字稿

Please standby. Good day everyone, and welcome to this EOG Resources fourth quarter and full year 2002 earnings conference call. This call is being recorded. At this time I would like to turn the conference 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 fourth quarter and full year 2002 earnings, cash flow and reserve results. We hope everyone has seen a press release. During 2002 we made several strategic decisions to position the company for likely strong natural gas prices in 2003 and 2004. We intentionally over spent cash flow for our cap ex and share buy back programs to set up our operations for 2003. Overall, we are pleased with our 2002 operation on reserve results and we believe we are well positioned for going in to 2003. This conference call includes forward--looking statements for oil and gas reserve estimates.

Any reserve estimates that are not specifically designated as having proved reserves, may include categories of reserves that EOG is not allowed to include in its filings with the SEC. The risk associated with forward-looking statements and reserve estimates and a cautionary note to investors regarding the use of reserve categories that are not permitted in section filings have been out lined in the earnings release and EOG's SEC filings and we incorporate those by reference for this call. With me this morning are Ed Segner, President and Chief of Staff, Loren Leiker, EVP, Expiration and Exploitation, Gary Thomas, EVP Operations, Bill Albrecht, our Vice President of Acquisitions and Engineering and Maire Baldwin, our Vice President Investor Relations.

Let me talk a bit about fourth quarter net income. As outlined in our press release, during the fourth quarter EOG reported net income available of 41.7 million dollars or 36 cents per share. To convert reported earnings to reflect actual cash paid out and eliminate the market to market loss on our norm al and previously disclosed oil and gas hedges, the following adjustments can be made to conform to some analysts practices of matching realizations to the settlement month. Add back the $7.1 million loss from the mark-to-market impact of our outstanding futures transactions, which is 4.5 million after tax, or three cents a share. Subtract the 11.2 million, 7.2 million after tax, or six cents per share of actual cash paid out during the quarter to settle commodity contracts and pay premiums on derivative contracts.

Adjusting for these items, adjusted net income available to common for the quarter was $39.0 million or 33 cents a share versus last year's $5.1 million or four cents per share on a similarly adjusted basis excluding the impact of one-time items.

For the full year, EOG reported net income available to common of 76.1 million or 65 cents per share. Results include the impact of the mark-to-market of outstanding futures transactions. One can adjust full-year results to reflect actual cash paid out and to eliminate the mark-to-market loss on outstanding transactions by the following.

Add back the 48.5 million mark-to-market loss, which is 31.2 million after tax or 27 cents per share. Subtract the 23 million, 14.8 million after tax or 13 cents per share of actual cash paid out over the course of the year to settle commodity contracts and pay premiums on a 2003 derivative contract.

Adjusting for these items, adjusted net income available to common for the year was $92.6 million or 79 cents per share versus last year of $377.1 or $3.21 per share on a similarly adjusted basis.

For investors who follow the practice of those industry analysts who focus on discretionary cash flow, discretionary cash flow available to common for the fourth quarter was $255.6 million or $2.19 per share. For the full year 2002, discretionary cash flow available to common was $777.8 million or $6.63 a share. The reconciliation of discretionary cash flow to net operating cash flows is shown in our earnings press release, which is posted on our Web site.

Now I'll address some of our operational highlights and then I'll talk about reserve replacement.

Operationally, we're pleased to note that we're one of the few companies that increased its fourth quarter domestic gas production, both sequentially and versus year-ago levels.

Starting with South Texas, we have three different geologic trends that we've had recent success in. In the Dinn Ranch 16,000 foot Wilcox play we achieved our target year-end 2002 exit rate of over 40 million a day net. We expect to maintain flat production rate through 2003 from this field. We recently completed the Buck Hamilton Number eight, producing 10 million a day and the Lopez Mineral Trust Number Three at a 12 million a day rate. We have a 50 percent interest in both these wells.

We've also extended our success in the South Texas Roletta (ph) Play and a re-emerging play for us in 2003 will be the Frio Play (ph) . We recently completed the city H&S (ph) number one well for five million a day and 150 barrels of condensate rate and we expect to drill 20 to 30 wells in this South Texas Frio Play (ph) in 2003 with an average 75 percent working interest.

During the fourth quarter we committed a bit of money to exploration in the shelf Gulf of Mexico and made a nice exploration discovery at South Tibelier (ph) block 156 at 15,000 feet and 174 foot of water depth. We believe this is a 50 DCFE (ph) one-well discovery and we expect to commence sales in the third quarter.

EOG operates and has a 50 percent working interest.

In the Mid-Continent Division, we've continued our hot streak in our Texas County Oklahoma drilling program, drilling 3,000 to 7,500 foot depth wells. We grew our mid-continent production from 65 to 85 net million cubic feet a day during 2002 and we plan to drill about 130 wells in 2003 in this division.

In our West Texas Horizontal Dibonion (ph) Play, we've had several good recent wells. The Nokie (ph) 1402 Dual Lateral at Allison (ph) Ranch is currently flowing three million a day, and appears to be a 4.6 BCFE (ph) well.

The Windham (ph) 108 number one H (ph) in our ATM area is flowing 6.3 million a day, and 350 barrels of condensate a day, and is a seven BCF well.

We have 100 percent and 96 percent working interest respectively in these wells.

Additionally, we're experimenting with vertical wells and barnet (ph) shale-type water fracks (ph) as an alternative method to horizontal drilling and acid fracks (ph) to access these dibonion (ph) reserves.

We also recently drilled a nice Montoya horizontal well. The Caprito (ph) 82 number 2 is currently flowing 10.7 million cubic feet a day, and we have a 38 percent working interest here with several higher working interest wells as follow-ups.

In the Rockies, we've continued to drill with a two-rig program in the Eton (ph) Mesa Verde formation, and results are very good. 11 out of 12 of these tasks have successful, and we plan to run two rigs in this play throughout the year. The recent Chapita (ph) Gas Unit number 808 was completed flowing two million cubic feet a day. It is a three BCF well and EOG has 100 working interest.

In Canada, our year-over-year gas volumes increased 22 percent, primarily from our Thousand Wells Shallow Gas Drilling Program. We expect to drill at least 600 to 800 wells in 2003 in Canada. Also, we recently completed a nice 100 percent interest Deep Basin Well in the Wapatie (ph) area that tested 10 million cubic feet a day from the Catoman (ph) formation. We expect to commence sales from this well in April. We expect to drill six Deep Basin wells in 2003.

In Trinidad, year-over-year gas production increased 17 percent, due to our mid-year startup of the CNC Ammonia Plant, where we provide 100 percent of the gas supply. We expect gas production to increase another 14 percent in 2003 since we'll have the full year's operation of this plant. In April, we'll commence a new 3-D survey over the 187,000 acres of new leases we acquired last year, and during the second half we expect to drill two exploration wells on this acreage.

We're working on additional gas contracts for either LNG (ph) , methanol or ammonia markets and hope to report on those by mid-year.

On another international front, we're pleased to announce that our first drilling investment in the Southern Gas Basin of the U.K. North Sea is successful. We fawned (ph) in 25 percent working interest from a major, and the well is a 120 BCF gross, 30 BCF net discovery that will be tied back to infrastructure, and is expected to come on line in 2004.

We plan to commit about $20 million of -- excuse me -- about 20 million of 2003 drilling dollars to the North Sea, primarily via farm ends (ph) . We will then assess results at yearend regarding whether we want to expand further in this area.

Now, I'll address reserve replacement of fining costs. In 2002, we achieved a 193 percent reserve replacement at a $1.06 per MCFE fining cost. Our North American reserve replacement was 158 percent, at $1.42 fining cost, down from $1.58 last year. Our reserve life in North America has increased to 9.3 years.

For the 15th consecutive year, our North American drilling-only reserve replacement exceeded 100 percent. We believe these are attractive fining costs and reserve replacement rates. Three other salient parameters regarding reserves and fining costs are as follows:

One, for the 15th consecutive year, our reserves have been separately reviewed by DeGaulier McNaughton (ph) and the internal reserve estimates are within 5 of D&M's estimates.

Two, we booked our Trinidad Perula (ph) conservatively, at about 250 BCFE, although we think the reserves are more likely in the 350 BCFE range.

And three, we continue to have one of the lowest PUD ratios in our peer group. Now I'll turn it over to Ed Segner to review cap ex and capital structure. segner: First on cap expenditures, total expiration development capital expenditures in '02 were 821 million dollars, including 71 million dollars of acquisitions. Approximately 25% was expiration spending and 75% development. Total capital expenditures for the year, 2002, including the Trinidad ammonia investments and normal IT hardware, etc, were 847 million dollars.

For the quarter, total expiration development capital expenditures were 206 million dollars, including 22 million of acquisitions. The acquisitions we made during 2002 were primarily in western Canada, where we increased our shallow acreage position. Capital-wise, interest for the quarter was 1.9 million dollars and 9 million for the full year. Interest expense increased for the quarter, reflecting the higher absolute debt level.

Moving to capital structure, December 31st, 2002, total debt outstanding was approximately 1 billion, 145 million. The debt to total capitalization ratio at year end was 40.6%, although our debt has increased since year end 2001, we still have the strongest debt coverage ratio of the peer group and one of the lowest debt to total cap ratios in the industry. We took advantage of the placement of the 11 1/2 million share block in November, that was tied up in bankruptcy court proceeding as an opportunity to buy back shares. The placement of the shares eliminated the other hang related to this block. In total, we repurchased 700 thousand net shares after option exercise offsets and an average price of $37.06 per share in 2002. This is the 8th consecutive year that we have reduced our share count.

The effective tax rate for the year was 27.2% reflecting a decrease in foreign taxes. The effective tax rate for 2003 is anticipated to be more normal at around 35%. The deferred ratio of 346% for the quarter and 253% for the year reflects the expenses of IDCs, intangible drilling cost and income tax refunds that we are, or have received in various jurisdictions. In terms of AK and guidance, guidance for detailed modeling in 2003 will be provided towards the end of the month once we receive board approval on our 2003 plan. We would also, at that time, issue full financials and footnotes for 2002. Now I'll turn it back to Mark for to discuss hedging and marketing and close out. papa: Thanks, Ed. Now I'll give you our thoughts on the North American gas macro and then discuss our hedging strategy. Our macro supply view hasn't changed much from our previous quarter's conference call. We expect if you fourth quarter domestic gas over year over year comps for all public companies to be down 6, including 1.4% of hurricane effect.

We expect domestic production to further decline two to three percent this year, this is 2003, assuming a robust drilling recovery and three to five percent without a drilling recovery. We expect 2003 Canadian imports to be down about seven tenths of a BCF (ph) a day compared to 2002, essentially offsetting an LNG (ph) import increase of the same amount. Additionally, exports to Mexico appear to be running about seven tenths of a BCF (ph) a day.

In total, we expect the U.S. gas markets will have to make due with about two BCF (ph) a day less supply in 2003 versus 2002, and the price consequences of this are reflected in the future's market.

I don't see much changing to ameliorate the 2004 North American supply situation, so I expect 2004 prices to look similar to 2003. We have to remember that in two years, our domestic supply has eroded from 52 to 48 BCF (ph) a day, and in my opinion, the best the industry is likely to do is stabilize production at 47 to 48 BCF (ph) a day over the next three to four years.

Regarding gas hedging, we're roughly 12 percent hedged with fixed price contracts for March through October, locking in a $4.85 price for those months and we've got a little less than 15 percent of our gas collared for January to December at ceiling prices sculpted by month, but averaging $5.43.

And in summary slightly over 20 percent of our expected 2003 North American natural gas production has some sort of price protection.

We have no swamps and are only slightly, only lightly collared in November and December, because we may enter next year's heating season with a very low level of storage gas.

Regarding oil, we've hedged about 20 percent of our January to December oil at a $26 average price.

In summary, for 2003, we expect to achieve approximately four percent year-over-year North American absolute organic natural gas production growth and total company production growth of five to six percent per basic share. Our estimated likely 2003 cap ex will be in the $950 million range including acquisitions, which will provide moderate free cash flow with these strong gas prices. We expect to use that free cash flow to either increase the dividend, pay down debt or repurchase shares.

As always our goal isn't to the largest independent E&P (ph) company, we'd rather be known as the most profitable and most efficient.

We're also pleased to note that late last year, a major investment house completed a thorough study and rated EOG as having the most conservative accounting and reserve booking methodology in the large cap peer group. We think that's particularly important in today's environment.

Thank you for your attention and we'll now go to Q&A. So Lori (ph) , do you want to handle the Q&A?

Thank you gentlemen. Today's question-and-answer session will be conducted electronically. If you would like to ask a question today, simply press the star key, followed by the number one on your touch-tone telephone. Again if you would like to ask a question, please press star-one.

We will pause for just a moment to assemble our roster.

Our first question today comes from Irene Haas (ph) with Standards, Morrison, Harrison (ph) .

Good morning everybody. Just two questions, if I might. Firstly the entry into the UK, North Sea, just sort of wondering, what kind of rate of return are you looking forward to?

And then secondarily, any news on the Merner and Decline (ph) ?

Yeah. Thanks, Irene. Yeah, in the North Sea area, in terms of the rate of return, we've got a hurdle rate across our all our investments in the company of a 15 percent after-tax cash-on-cash un-levered rate of return, and so that would be our hurdle rate in the North Sea. Obviously, the first well being a success is likely to exceed that rate of return.

In terms of your question on the Merner (ph) anticline, for those of you that aren't aware, we've got a fair amount of acreage in western Wyoming that is the next anticline to the west of the Pinedale anticline, where they've had the Jonah (ph) field and a lot of other discoveries, and we think this acreage is highly prospective. We have recently shot a 3-D over that acreage, and we'd be looking to get that 3-D out of processing, and likely in the third or fourth quarter, we'll spot our first well in that Merner (ph) anticline area.

Any news on your competitor's well, and whether the pipeline's been built, and all that good stuff up north?

We don't have any news on the results of the competitor's well. We do know that a pipeline has been constructed and really runs by our acreage now.

Thank you.

OK, Irene.

Thank you. We will now hear from Mark Meyer with Petrie Parkman.

Good morning, Mark.

A question on Trinidad. You've booked some pretty big reserves again this year -- no surprise -- and you characterize Perula (ph) as conservative. Looking at what I think you consider to be your next market opportunities -- methanol, ammonia, LNG (ph) -- LNG (ph) being a being a big step up in '06 -- what kind of critical mass do you think you need to have in place in terms of proved reserves?

We've already go the critical mass in place and the reserves developed to chase a 15 to a 20-year contract for either LNG (ph) , methanol or ammonia for production rate in the range of between 60 and 100 million a day for that timeframe. And so all three of those potentials are being actively worked right now. As you may know, Atlantic LNG trained six (ph) has not yet received approval from the Trinidadian government. We have heard that that may be forthcoming sometime in the first or second quarter, and we think at that time we'll likely know whether or not we're able to capture an LNG (ph) contract. There's also a very large methanol plant that is getting close to approval by the government there.

So, there's a pretty target-rich environment right now for projects down there, and we've already got the gas in place and located. So, we feel pretty good about the reserve situation to chase other markets.

Yeah, so we could see similar magnitude for the next few years?

Yeah, you know, our plan there is we chase a market for our existing reserves that we've recently found, and then, hopefully, by the third or fourth quarter, we're gonna find some new reserves by drilling these two expiration wells I mentioned, which will then put us in place for next year to chase one additional market. So, that's the kind of two-year game plan down there, Mark.

OK. A question on your two to three percent projection for 2003 decline. You characterized the drilling recovery as robust in that scenario. What kind of average rig count do you think for the year?

Yeah, the model we ran on that started January 1st with a gas-directed rig count of 750, escalating to 1,000 rigs by yearend. And we're now in February, and obviously we haven't seen that recovery. So, that's why we're giving that beckon number of a more steep U.S. gas production decline if we don't see a rig recovery.

Just to clarify, that's 1000 gas directed? papa: Yes. meyer: OK, one other question, specifically on den ranch (ph) , you cited a 40 million a day net exit rate. Is the intention to keep the exit rate flat through '03? papa: Yes, I'm going to have Gary Thomas answer that.

Yes, Mark we are running about 100 million a day there through the plants that we have. That's full capacity and yes, that is our intent to maintain flat production at den ranch (ph) through 2003.

Yes, and that 100 million a day translates on a net revenue basis to us, so roughly about 40 million a day. meyer: OK, thanks guys. operator: Alan Stepper with Durson Lurman Group Inc (ph) . stepper: Yes, overall when you look at your 2003 development drilling program, is it front end loaded, back end loaded or equally distributed through the year? If you could also comment, as well, regarding your exploratory program, break the two different programs up, please?

Yes, in terms of the development program, its likely that the first quarter activity is going to be a bit lower than the second through fourth quarters, and this is, its got nothing to do with trying to time things at all, its just got to do with the rate at which some of our projects are out of 3D and things like that. In terms of exploration program, I would say most of our bigger exploration shots will be done in the second half of the year for example, we have one deep water wildcat called the Tuscany Prospect that several other chains are also advertise.

We have a 36 1/2% carried interest when that well is drilled, which will likely be in third or fourth quarter of the year. The Myrna well will likely be in the second half of the year. Trinidad exploration wells in the second half of the year.