西南能源 (SWN) 2003 Q4 法說會逐字稿

Good day, everyone and welcome to the Southwestern Energy company fourth quarter and year-end earnings teleconference. This call is being recorded. At this time, I'd like to turn the conference over to the President, Chairman and CEO, Mr. Harold Korell, please go ahead, sir.

Good morning and thank you for joining us. With me today are Richard Lane, our executive Vice President of Exploration and production and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press releases announced yesterday regarding our 2003 financial results, year-end reserves and guidance for 2004, you can call Sharon at 281-618-4784 and she'll fax a copy to you.

Also, I'd like to point out that many of the comments during this teleconference may be regarded as forward-looking statements and involve risk factors and uncertainties that are detailed in our Securities and Exchange Commission filings. We also would warn you that these forward-looking statements are subject to risks and uncertainties. Many of which are beyond your control. Although we believe the expectations expressed are based on reasonable assumptions, they are not guarantees of future performance and actual results or developments may differ materially.

To start out, 2003 was a banner year for Southwestern Energy. We set records for production volumes delivered with 41.2 Bcf, which was 3% growth over last year, a reserve replacement of 351%. Total reserves of 503 billion cubic foot [INAUDIBLE] . Net income of $48.9 million and cash flow of $132.3 million. Again, we achieved all of this organically, meaning that we internally generated the ideas into which we invested our cash flow. Drilling wells defined New Orleans gas reserves. But most importantly, our formula delivered again in the area of value-added per dollar invested.

Using year-end prices, we created in excess of $1.40 of present value for each dollar we invested in 2003 in our E&P operations. A metric that we're very proud of. Now let's talk about the plan for 2004. Our total company plan to capital investments for 2004 is $203.5 million, of which $194 million will be invested in our E&P business and $9.5 million for our utility and other corporate use.

In our E&P program, our primary areas of focus will be building on past successes. We plan to invest approximately $111 million or 54% of our total capital in East Texas. This will include the drilling of 70 wells at our Overton Field in 2004 compared to 57 drilled there in 2003. In addition, we will be drilling in East Texas in a new area we call stockman, where we have recently drilled an encouraging well. In the Arkoma Basin, we plan to invest approximately $44 million or 22% of our total capital to drill over 80 wells and perform over 95 work overs in the basin. This includes approximately 60 wells in the traditional Fairway and Oklahoma areas and up to 20 wells in our ranger anta Klein area, which is now a significant development project. Our plan for the Permian Basin is to invest approximately $8 million or 4% of our capital. And Richard will tell you today about a significant well that we have drilled on our River Ridge Devonian prospect in the Permian. We plan to invest approximately $13 million or 6% of our capital in the Gulf Coast area of south Louisiana and Texas. In South Louisiana, we plan to finish testing our prospect ideas in our Duck Lake 3-D project as we get land and partners put together. And at this time, it is unlikely that we will, as a company, do another 3-D project in south Louisiana.

In 2003 we began working on projects we are calling new ventures. We invested $11 million in acquiring 345,000 net undeveloped acres of land on these projects in 2003. In addition, in early 2004 we acquired an interest in some 5,000 acres of land on a coal bed methane project in Montana. Richard will discuss this in more detail.

In 2004, we plan to acquire additional acreage associated with these projects and begin the drilling, testing of these new ideas. Our current plan calls for vesting approximately $18 million in our new ventures areas in 2004.

Before I turn this over to Richard, I would just say that we're looking forward to another record year in 2004 as our production grows in the double digits and with that I would like to turn it over to Richard for an update of our E&P operations and then to Greg Kerley to address our 2003 financial results and the outlook for 2004. Richard?

Thank you, Harold and good morning. 2003 was another successful year for the Company's E&P business.

As Harold mentioned, we set company records for production reserve additions and total proved reserves. Our production for the year was up 3% over the prior year to 41.2 Bcfe, our fourth consecutive year of organically driven production growth. This production growth was achieved despite the loss of production from the sale of our Mid-Continent properties and the lack of significant production ads from exploratory drilling during the year. Additionally, production for the fourth quarter of 2003 was 11.2 Bcfe, up 18% from 9.5 Bcfe in the fourth quarter of 2002.

For 2003, we achieved an average finding and development cost of $1.18 per Mcfe, excluding revisions. Including the effective revisions, our finding and development costs in 2003 was $1.32 per Mcfe. Our three-year reserve replacement ratio was 262% and our three-year average finding and development costs was $1.12 per Mcfe excluding reserve revisions.

We achieved a significant milestone for the Company in 2003. We ended the year above the 1/2 Tcf reserve Mark with 5.31 Bcfe reserves. We ended 2002 at 14.3 Bcfe and for 2003, we added 144.5 Bcfe of new reserves, produced 41.2 Bcfe and had a net downward revision of 13.5 Bcfe for a year on year increase improved reserves of over 20%. Approximately 91% of our approved reserves were natural gas and 82% were classified as proved developed. An increase over 2002 when approximately 77% of our reserves were classified as proved developed. Our average reserve life or RP ratio was 12.2 years -- 12.2 years at year-end 2003 and this is indicative of the low risk long life reserves that we are finding and developing in East Texas and in the Arkoma Basin.

In 2003, we drilled a total of 139 wells compared to 65 wells in 2002. Of the 2003 wells, 110 were [INAUDIBLE], 16 were dry and 13 were in progress at year-end. Our drilling success rate was 87%. Total capital investment for our E&P operations for the year was $170.9 million. The majority of the increase in capital from the $85.2 million in 2002 was dedicated to our Overton Field development where we increased our drilling activity from 18 wells to 57 wells drilled and completed in 2003.

In the Arkoma basin, we drilled 60 wells, of which 42 were successful and 5 were in progress at year-end. We added 28.8 Bcfe of proved reserves in the Arkoma in 2003, replacing 152% of the 18.9 Bcf that we produced there. In 2003, we significantly increased our drilling activity in our Ranger Anticline project area located in Yell County, Arkansas. Early last year as we commented, we obtained regulatory approval from 640 acres per well to 80 acres per well in the Ranger Anticline area. In [INAUDIBLE] we successfully drilled 10 out of 12 wells at Ranger, including adding 13.1 Bcfe of reserves and a finding cost of 81 cents per Mcfe.

Additionally at year-end, we had three wells in progress in the area. Our wells at Ranger typically target the upper and lower born sands between 5,000 feet and 8,000 feet and our average working interest in the producing wells we have there is about 78%.

During 2003 we increased our acreage position at Ranger to 4400 gross developed acres and 37,100 gross undeveloped acres. As we've previously announced in the fourth quarter, we reached total depth on an exploration well, the Smith 110 well, located about 6 miles west from our existing Ranger production. Since the first of the year, we completed and tested this well at 2.7 million cubic feet per day from the born sands. Additionally, we recently drilled a second well one mile south of the Smith well. The -- number 215 logged in excess of 350 feet of apparent pay and is currently being completed.

Additionally, we're drilling right now on a well that we call our Albright well and it's about midway between the Dogle and Smith activity and our producing area to the east and we're seeing encouraging results from it, as well. We expect the Dogle and Smith wells to be brought on-line in the second quarter -- [ loss of audio ]

Please stand by, we temporarily lost connection with the moderator. Please stand by. We will reconnect him momentarily.

Okay, thank you. We tried to pick up where we think we left off with you, back up a little bit. I was talking about our Ranger Anticline project and during [INAUDIBLE] we increased our acreage position at Ranger to approximately 4400 gross developed acres and 37,100 gross undeveloped acres.

As we previously announced in the fourth quarter, we reached total depth on an exploration well, the Smith 110 well, located about six miles west from our existing Ranger production. Since the first of the year, we completed and tested this well at 2.7 million cubic feet per day from the born sands. Additionally, we recently drilled a second delineation well, one mile south of the Smith well.

This well is the Dogle 215 and it logged in excess of 350 feet of pay and is currently being completed. Additionally right now we're drilling on a well we call our Albright well and it's about midway between the Smith and the dogle and our HVP acreage to the east. And it's another step out well for us and we're seeing pretty encouraging results from it, as well. We expect these wells to be brought online in the second quarter upon completion of a six-mile pipeline, allowing for gas sales.

In 2004 we plan to drill about 20 wells in the Ranger Anticline area, including additional tests on our undeveloped acreage. While geologic complexities and service limitations will play a role in the development of the western portion of our lease block, the Smith and dogle wells are very encouraging developments for us on this part of our acreage.

Our Overton Field development program has continued to yield very good results. In 2003, we drilled and completed 57 wells with an additional 6 wells either being drilled or completed at year-end. We maintained our 100% success rate at Overton since we began our drilling program there in 2001. Our net production from the area was 13.6 Bcfe in 2003 as compared to 5.9 Bcfe in 2002. Including all capital costs, such as drilling, land and an allocation of capitalized interest and expense, we invested $97.3 million in Overton in 2003 and added 102.2 Bcfe of new proved reserves for a finding development cost of 95 cents per Mcfe. Based on drilling costs alone, our finding development cost there was 86 cents per Mcfe.

Gross production in the Overton Field as of the end of the year was 60.1 million cubic feet per day. Initial production rates of all wells drilled in 2003 averaged 3.3 million cubic feet per day and we estimate that the average expected ultimate recovery of the new wells drilled is approximately 2.2 gross Bcfe per well.

We're also continuing to decrease the cost to drill a well at Overton, in the fourth quarter with one of our flex rigs, we set a new record by taking less than 15 days from spud to total depth on the wear 17 well . In 2003, our average drilling time has been 23 days per well and this compares very favorably to the average drilling time of 27 days per well we achieved in 2002 and 35 days per well in 2001. Our 2004 plan for Overton is to drill another 70 wells with some locations being 40-acre spaced wells. Based occurrent well performance in the field, we also anticipate a significant drilling program in 2005. Although current field rules allow for development at optional 80-acre spacing, we have applied to the Texas railroad commission to change the rules to allow for optional 40-acre development areas of the field where it is needed to efficiently produce the reservoir.

In addition to our Overton Field, we drilled a successful cotton valley sand well at our Stockton prospect, about 50 miles southeast of Overton in Shelby county, test. The Beckham No. 1 tested at 1.8 million cubic feet per day from the cotton valley sands at 10,200 feet. Southwestern operates this well with a 70% working interest. Now, we expect to follow up this discovery with two to four development wells this year and are hopeful that this could turn into a bigger project for us. As reported last time, we made a significant discovery on our River Ridge prospect in the third quarter.

This discovery was made by deepening the Rio Blanco 4-1 well to the Devonian formation at 14,190 feet. The Devonian open hole completion is currently producing 700 million cubic feet per day with 125 pounds of flowing tubing pressure. We hold a 12.5% working interest in this discovery located in Lee county, New Mexico. More importantly, we have currently reached TD and are testing the Rio Blanco 33-11 well, a direct offset in which Southwestern holds a 50% working interest. Based on drill stem tests and formation samples, it appears that this well has also penetrated reservoir quality pay.

The initial DST, which tested the top 100 feet of the Devonian flowed 3.2 million cubic feet per day. And the second DST, which selected deeper pay, yielded an additional 10.6 million cubic feet per day at 2800 pounds of pressure. We now believe the overall prospect has approximately 30 to 50 Bcfe of gross potential.

In south Louisiana we reached total depth on our Canvasback prospect in January. This well was our first exploratory test in our Duck Lake 3-D seismic prospect. The canvass back prospect targeted the lead to sell the sands at approximately 18,200 feet. The wells came in structurally high with the objective sands present but they were not productive. We operated this well with the 50% working interest. Our next south Louisiana exploratory tests will be our La range prospect, also in the Duck Lake 3-D shoot. This 70 Bcfe prospect will be targeting the sands at about 15,600 feet.

We also operate La range with a 50% working interest and expect the spud to well in the second quarter. Since our first discovery in December of 1999, the efforts of our exploration program, south Louisiana, have resulted in 9 successful wildcats out of 21. After three years of good drilling results during '99 through 2001, we did not have a significant discovery in south Louisiana in 2002 or 2003.

Our recent exploration activities in this area are not meeting our economic criteria. Therefore we're reducing our investments there. While we still plan to drill two exploration tests in south Louisiana in 2004, we expect to decrease our activity in this area going forward.

As Harold mentioned, in 2003, we continued implementation of our plan to identify and acquire undeveloped lease hold positions in new venture projects to provide opportunities for the future. One new opportunity is our reed point project located in the crazy mountain basin of Montana. We currently control 95,000 net acres within the project area. The vast majority of which was acquired this year and plan to spud our initial test well this quarter. If successful, we will follow our initial test well with a 4 to 8 well pilot program to further determine the economic viability of this coal bed methane play.

In total, we are planning to invest $194 million in the Company's E&P segment 2004. We will drill approximately 180 wells, heavily weighted to our low-risk, high-return programs. We plan to accelerate the development of our Overton Field in East Texas by drilling 70 wells with five or more rigs running continuously in the field. We anticipate drilling over 80 wells and to perform 95 workovers in the Arkoma Basin, including the 20 fuels our Ranger Anticline area in 2004.

Our 2004 capital program broken out by geographical area where include investing approximately $110.9 million in East Texas. $44.3 million in the Arkoma Basin, approximately $7.8 million in the Permian Basin, $12.8 million in onshore Gulf Coast region, of which $9.3 million is for south Louisiana. And $18.2 million in new venture projects where we are working on ideas for the future.

We continue to be focused on our strategy of adding value through the drill bit with 80% of our 2004 capital allocated to drilling. As always, the primary focus of our program is to create at least 1.3 of discounted value for each dollar we invest. By executing our drilling intensive 2004 plan, in proven, successful areas, we can expect 2004 production to be 47.5 to 50 Bcfe. An increase of 15 to 20% over our 2003 levels.

In summary, we had a strong year in 2003 and are looking forward to a very productive 2004. We are well positioned with our low risk, high PVI project inventory to continue to achieve superior results while building digital inventory for the future. I will now turn it over to Greg Kerley who will discuss our financial results and talk about additional guidance for 2004.

Thank you, Richard and good morning. As Harold indicated, 2003 was an exceptional year for Southwestern. We ended the year strong with record fourth quarter earnings of $14.9 million or 41 cents a share, more than 3 times our earnings of $4.6 million or 17 cents a share for the same period in 2002.

Our net cash provided by operating activities before changes in operating assets and liabilities was $37.4 million in the fourth quarter of 2003. Up 80% from $20.8 million in the fourth quarter of 2002. Higher commodity prices and an 18% increase in production led to our improved results for quarter. For the full year of 2003, we had record net income of 1.43 AIDS share, up 242% from $14.3 million or 55 cents a share in 2002. Net cash provided by operating activities before changes in operating assets and liabilities also set a new record at $132.3 million in 2003, up 66% from $79.8 million in 2002. Our improved financial results were primarily due to higher realized gas and oil prices and an increase in our production.

Our outlook for 2004 is a very positive one and we expect our E&P program to generate 15 to 20% growth in our production and reserves. We're targeting 2004 oil and gas production of 47.5 to 50 Bcf equivalent and assuming NYMEX commodity prices of $9 per Mease of gas and $26 per barrel of oil in 2004, our net income should be between $69 [INAUDIBLE] and $72 million for the year. Using that same price deck, we expect our net cash provided by operating activities to approximate 184 to $187 million in 2004.

Operating income for our E&P suggestment $84.7 million in 2003, compared to $36 million for the same period in 2002. The increase in 2003 was primarily due to a 40% increase in our average realized gas price and a 3% increase in production volumes. We realized an average gas price of $4.20 per Mcf during the year, up from $3 an Mcf a year ago. Our average realized oil price in 2003 was $26.72 a barrel, compared to an average price of $21.02 a barrel last year.

Going forward, approximately 60 to 70% of our targeted gas production in 2004 is hedged at attractive prices. Our current hedge position is detailed in our guidance press release issued yesterday. Our E&P segment continues to benefit from some of the lowest operating costs in the industry. It was 39 cents per Mcf in 2003 compared to last year's production expenses of 45 cents an Mcf.

In 2004 we expect our per-unit lease operating expenses to range between 38 cents and 42 cents an Mcf. Taxes of the income taxes were 42 cents per Mcf in 2003 compared to 19 cents an Mcf in 2002. Assuming a NYMEX price deck of [INAUDIBLE] and $26 oil, we would expect our taxes to range between 22 cents and 26 cents an Mcf equivalent in 2004.

Our G&A expenses for E and P segment were 41 cents a year, compared to 43 cents in 2002. The increase was primarily due to higher pension, insurance, and incentive [INAUDIBLE]. We expect our per-unit G&A expenses to range between 38 cents and 42 cents an Mcf in 2004. Depreciation, depletion and amortization increased slightly during 2003 due to higher production volumes and a higher amortization rate. The amortization rate for the full cost pool for 2003 was $1.17 per Mcf compared to $1.16 last year. We expect the amortization rate for 2004 to be in the range of $1.18 to $1.22 an Mcf equivalent.

Operating income for utility was $6.8 million in 2003, down from $7.6 million last year. A decrease in operating income was due to increased operating costs and expenses and reduced usage per customer due to customer conservation brought about by higher gas prices. In October of 2003, our utility implemented a 4.1 million annual rate increase and was also allowed to recover certain additional costs totaling $2.3 million over a two-year period.

In 2004 we are projecting the gross margin from our utility, which represented the utility's [INAUDIBLE] less its gas purchases, to approximate 53 to $55 million and the utility's operating income is expected to be approximately 8 to $10 million assuming normal weather in 2004. Our operating income for our gas marketing segment was $2.6 million in 2003 compared to $2.7 million in the prior year and in 2004, we expect that segment to generate between 2 and $2.5 million of operating income. Other projected expenses in 2004 included our net interest expense which we expect to be between 17.5 and $18.5 million. Please refer to our guidance press release issued yesterday for additional detail regarding our estimates for significant operating and financial data for 2004.

Our capital expenditures for 2003 totaled $180.2 million, including $170.9 million invested in our E and P operations, $8.2 million, invested in our gas distribution system improvements and $1.1 million for general corporate purposes. Of the $170.9 million invested in the evidenced P, $17.8 million was in exploratory drilling, $124.4 million in development drilling and workovers. $16 million in land and lease hold and seismic expenditures. $3 million for producing property acquisitions. And $12.7 million in capitalized interest and expenses and technology-related expenditures.

In 2004, we plan to invest a total of $203.5 million and expect to fund our capital program through our cash flow generated from operations and our revolving credit facilities. Our equity offering in the first quarter of 2003 and our strong earnings led a significant improvement our financial position and leverage during 2003. Our total debt to capitalization ratio improved to 45% at December 31, 2003 from 66% at December 31, 2002.

In January of this year, we entered into a new $300 million, three-year unsecured q-and-a.

Thank you. The question and answer session will be conducted electronically. If you would like to ask a question, you may do so by pressing the star key followed by the digit 11 on your telephone keypad. That's star 1 if you would like ask a question. We will pause for just a moment. Our first question comes from Ron Mills with Johnson Rice.

Good morning, guys, how are you all.

Good, how are you?

Good, just a couple of questions, especially as it relates to 2003 production and your -- your guidance for 2004. What -- and some of the revisions on reserves. Were most of the revisions on reserves at -- at south Louisiana and in terms of production coming in, you know, towards the bottom end or a little bit below the original guidance due to production declines related mostly with south Louisiana?

Well, it really is a combination of things, you know, south Louisiana. One, in 2003, was that if you will recall, we drilled a second well at north growback -- actually drilled I guess it was our third well and we -- we pretty much expected that to be productive. It turns out that it was a dry hole. So, that caused us to have to redo our mapping on north growback, which decreased the size of it. So that was a negative. We also had an old well that had, I don't know even in the Company had acquired it was part of one of the acquisitions sometime before, I think I came along here, is it called lake decade, Richard?

Right.

Where we lost a well due to mechanical problems so we were, you know, we lost a production there, plus we lost those reserves. And then we've had some decline that's built in in south Louisiana but as most of you know, those are water dry reservoirs and it's hard to know where the oil -- where the gas water contact is in them unless you had drilled through it. So, we also had that, but the combination of those three things pretty much make up, you know, the -- the reserve revisions that we had and a lot of it was primarily south Louisiana.

Okay. And then how about at Overton in terms of the actual well performance versus what you had expected? I know you ended up drilling, you know, about 10 more wells than you had originally planned and production was a little bit better than what you all talked about. Have those wells performed as you would have expected from -- from your production curve?

Well, Richard, I think highlighted what the production on those wells were, I think his numbers were that they averaged 3.3 Bcfe as initial production -- 3.3 million a day of initial production rates. We're seeing reserves there on the wells that we drilled in 2003 that still, on a gross basis, are 2.2 Bcf per well. I do recall a time at some times talking about initial production rates of 3.5 to 3.6 million a day.

So, maybe on average, you know, whatever you call the IP on average might be slightly lower than maybe we had talked about even a year ago at this time. But it's not a substantial difference and the economics of those wells is still extremely good, some of the best PVIs of anything we invest in in our company.

Okay. And [INAUDIBLE] expand a little bit on the Ranger Anticline since you have a couple of wells, one of which is production-tested and the second one with the 350 feet of pay, curious how that relates to the amount of pay in the first well and what the -- what the expectations would be in terms of production rates and especially in that first one, the 2.7 million meeting which you would have expected?

Yeah, I mean the rate -- this is Richard.

Uh-huh.

The first well we tested was the Smith. That rate was about 2.7 million cubic feet per day. You know, that's kind of in the range of what we've been seeing out there. It's, you know, that property, both from what we find in net fee to pay and how they test is a great deal more variable than say our Overton kind of performance, but the -- the Smith had significantly less pay, just to address one of your questions directly. I think it only had about 50 feet of pay and, you know, the -- the variability is -- is quite extensive. In the HVP area where we have a lot of producing wells, we see that same thing and sometimes the -- the wells that have thicker pay aren't necessarily the very best wells but it's hard to give you what an IP for the dogle would be, there's certainly a lot of pay in it and we're really encouraged by that, but it's hard to tell you right now what kind of test rate we'd have there.

And just to add to that, recalling, for those of you that followed that project, we are drilling there on a thrust faulted ant Klein which has thrust sheets one upon the other and oftentimes we will find a repeated section, so, it can be additive to the feet of pay you have in an individual well, just depending on exactly where you are on -- on the structure. So, when you get the feet of pay like we're seeing in this dogle well, that's a big number. You know, if -- we also have to deal with the matter of how do you -- we fracture stimulate all of the wells and we're now in the process of trying to design that. How will we [INAUDIBLE] stimulate it? And, you know, we'll be reporting probably at the end of the first quarter as to what we know on that. But it's certainly the fact that we have 350 feet of pay is not bad news, it's good news.

It's real encouraging. And then the Albright well I mentioned is about halfway going back east, halfway to where the -- our proven wells are, our producing wells and, you know, where -- we don't have any logs on it yet, but we're seek good shows in it and we're pretty encouraged there. Some areas of the field we're producing mostly from the upper [INAUDIBLE], other areas it's the lower [INAUDIBLE]. We're seeing a mix of that in the recent wells and that's encouraging, too.

Thank you, guys.

Once again, that is star 1 if you have a question. Also, if you're using a speaker phone, please make sure your mute function is turned off to allow your signal to reach our equipment. We will go to David Heikkinen with Hibernia South coast.

Good morning, guys. First, a comment and then a question. Like the lower pug percentage relative to peers with still solid finding costs, I think that reflects some conservativism. The question on fourth quarter production getting into specifics, do you have a [INAUDIBLE] of production by area?

For 2003?

Yeah.

Yeah, our was 4.9 Bcfe, East Texas, 4.2, Gulf Coast, 1.1 and the Permian: 1.

Okay. And then on the Ranger Anticline with the extension wells, do you have a feel for number of probable or possible locations that you would have that in that area yet? Or are you too early?

I think it's too early to really just kind of throw a number up there when these wells are just now drilling and tending to them much we need to get a full evaluation of them, but it's very positive. We have a big acreage block there and have more acreage -- actually east of our proven producing area, and, you know, in my comments I mentioned the geologic complexities and Harold talked more about that. They are significant both in -- in the structure and in the -- [ INDISCERNIBLE ] -- and then we have, you know, we have that lake right in the middle of that acreage block and so, you know, all these things will come into play and I don't have a number for you right now, but, you know, I think it's very encouraging that there will be some more significant development.

All right.

I'd like to again to add to that. The area that we have been talking about in the Smith and dogle are within the defined waveland field outline in which we have regulatory approval in the state to drill wells on 80 acre spacing. And -- and we have been down spacing that 7 sections that we consider proven in the main body of it and now we've stepped over 6 miles here and no doubt it's more than encouraging, it's -- it's a, you know, it's pretty exciting, really, to me, on what we -- what we have found here. And it's -- it's on trend, it's, you know, the in fact we found the sands over there and we've got production over there is no doubt very much a positive.

And you've got roughly 4 to 8 sections kind of on the north side of the lake, depending upon how you can develop around the lake, is that right? Over there?

You could -- you could -- Richard, do you have the map handy? I mean you can count like -- yeah, that's right.

So, it's about the same size of the main development area, potentially.

And then the question is how much, you know, down structure can you drill on this?

Can we drill -- how much can we drill under the lake, those types of things.

Okay. When do you think you will be able to provide some additional details on Stockton as far as amount of acreage that you have and then what type of potentials could be there? And a couple of two to four development wells, is it mid year that you will have additional details? Or is it now? Or what are your thoughts there?

Generally speaking it will be later in the year. We are -- we're assessing what we have currently drilled. We have plans for some more drilling and aps and, you know, one -- again, a little bit -- one of those things we may want to increase our positions some out there. So, you know... We -- we don't, you know, we're probably not going to take a lot more about it here, except what we've said.

Okay, so, nothing about objectives that you're after or anything along those lines?

Well, I mean it's cotton valley and we already have about 3800 acres.

Okay.

And we can see our way to some, you know, some offsets to this first well here, you know, pretty straightaway.

Okay. Then just one final question on the new venture areas and then coal bed methane. I don't know what -- where exactly is the crazy mountain area? Where in Montana, just trying to get an orientation for the acreage that you've acquired.

Yeah, it's, if you're familiar with Wyoming it would be off the northern end of the big horn basin, which places it south of Billings and I guess it would be west of Billings, just a little ways.

Okay.

Not a little ways, you know, 150 to 70 miles, 80 miles, something like that.

Okay. All right. Thanks a lot.

And now we have Amir Arit with Friedman Billings Ramsey.

Good morning, guys, you answered most of my questions. Just one other question on the Ranger Anticline area. The 350 feet of pay, is that net or is that growth?

That's net.

That's net. And so does that mean you still have further step up potential on the east?

East of that well?

Yeah, east of that well.

Yeah.

So, you haven't really hit the boundary here in terms of the field?

Well, actually, Amir, where we have been, it sounds like you're a little confused maybe on the geography there. We are drilling six miles west of the main body of the field now.

I'm sorry, that's what I meant. So, further west of the wells that you've drilled out there.

We are -- if you -- we have the main body we've been drilling in and we moved six miles west of there and drilled these two wells.

Yep.

And then Richard was commenting on the Albright which is back toward the main field, which -- which is between the main field and -- and the dogle and Smith. So, is your question -- you ask is there a potential east? Yes, there definitely is. That's where the field is and where we're drilling the Albright. And the west -- is that the question?

Yes, that's the question, the dogle well, does it mean you have a lot more potential west of the Smith and dogle well that you've drilled?

Yeah, well that's -- that's certainly something that interests us. You know, this -- this anti-Klein runs east and west. It is a question of how far off the flank of it you can drill and also is there sand there? There is still potential out there, yes, definitely.

Okay. And just one question in terms of the negative reserve provisions. I think that includes the 15.5 negative reserve revisions includes positive price revisions in there?

That's correct.

Do you know what the number would be if you broke them out,terms of reserve-related versus price-related revisions?

Yes, about 6.7 of upward related to price.

Okay.

And if you just look at the -- if you look at the Company as a whole and take the Gulf Coast out as a whole we were positive. So, really -- really the focus of downward stuff was there in the Gulf Coast.

Okay. Thank you very much, guys.

We'll move to Robert Christianson with Buckingham Research.

I got to try, Harold. You said 345,000 acres of other projects. So, is it fair to assume that 345,000 acres is not just one place?

I think the answer to that is the obvious answer is that as we have been talking about new ventures throughout last year, is that what we're doing there involves competitive -- very competitive situation and we are not interested in anyone else figuring out what that is, so, you know, rather than answer any questions about that, we have just decided to -- to say, at this point in time, for competitive reasons, we -- we aren't going to address that.

That's fine. I'm still not clear where the Albright well is, is it, what, north of the lake? Which side of the lake is Albright on?

It's on the north edge of the lake. It's in that -- you know,that median row of sections where most of our activity has been. And it's about halfway between the -- the Smith and the -- and the -- and our seven-section producing area.

Okay.

Basically east/west, all of those wells are kind of in the line there.

Yep, thank you. And then Permian well. I didn't get the specifics of it. What's your working interest in this well? It's being -- you get drill stem tests -- I didn't get the working interest.

The -- there's two wells, Bob, the first well that was the discovery well, we have 12.5% working interest.

I got that, yep.

And this one we're just on, we have 50% working interest.

Devon operates it.

Right.

It looks really good. The reservoir looks really well developed.

Okay. That's about it. Thanks a lot.

You're welcome.

We'll go to Michael Bodino with Sternago and Lee.

Good morning, gentlemen. Good quarter, glad to get the south Louisiana stuff behind us for a change and out of all the numbers. A couple of quick questions, relative to the crazy mountain area. And if you talked about this, I apologize. Do you have any information relative to coal thickness, gas content, infrastructure that you can provide on this area?

Well, we -- Mike, this is Richard. You know, of course we looked at all that stuff thorough analysis of everything that was available to us before we -- obviously before we pulled the trigger on the land there, but it's pretty Frontier. The data that's available there comes from drilling for -- for other objectives but, you know, there is -- there is a significant amount of well control there that let's you map the distribution of the coals and measure the thickness of them and map all those kind of things.

And then the -- you know, the other typical type of data that you would like to have, excuse me, like gas content, absorption properties, permeability properties, you know, what's the water like, that's a little harder to come by. We do have some of that data from cuttings, from wells in the basin there. And so we have incorporated those into our analysis, as well. But, you know, that -- the first well here really the objective is to -- is to get state-of-the-art data on all of those kinds of things that you -- that you want to have for this kind of play.

From a -- from the data that you've gotten to date, is it homogenous enough over an area that one core from one well will provide you enough data to [INAUDIBLE] a determination whether to move forward with this?

Well, yeah, we think it will be a decision point for us whether we go on to the pilot program, yes.

Is -- is it an area of a lot of thin coals? Or is it, you know, an area where you have some very thick coals?

They're -- you know, we think they're concentrated in a nice manner. It's not one big thick coal, but there is an interval in the -- there that it's pretty concentrated with thicker beds within it.

Okay. And on the Ranger Anticline, since we all want to ask a couple of questions about that, any chance that you're going to move out to that -- move out and recomplete that well to the east that had the lower pay and take another look at that?

Yeah. We've got that in our project inventory and looking at that and, you know, we've learned that -- we've learned some things by continue to develop the -- the main part of the field that -- that has us pausing and looking back at that stuff to the east. These wells will calculate the -- the logs will calculate real high waters -- high water saturations and still be gas productive, water-free gas productive and so looking back at that area now with more data and more rock property data from the main part of the field, yeah, I think there's some potential there.

Okay. And -- and relative to the program out there this year, is it going to be spread across the acreage or is it going to be more concentrated still on the eastern side and continued development in that area?

It's going to be spread across. You know, the 20 wells -- I think as we see it right now is subject to change, but, you know, the breakout would be about 8 or 10 of them in our -- in our known area there, continuing to down space. And about that amount to the west. And then in the west, you know, some of those wells will be, you know, probably offset these couple wells in the next 80 and then other wells out there in the west will be the -- maybe further try to delineate some acreage not right next to them. And then something in the east, probably.

And one last question, relative to the -- the -- the dogle well and the River Ridge well, you know, those wells were not in the year-end reserve, so, everything you find, you've announced here, is new -- is new reserves for the '04 year, right?

Yeah, the -- for the River Ridge prospect, we actually had, you know, because the first well was drilled, we had about -- I think a total of about 4 Bs that did make it into our '03 numbers there.

Okay.

And the dogle would not have been in those numbers.

Okay. That's all I have. Guys, great year and let's do it again this year!

Thank you.

Thank you.

Jeff Mobley with Raymond James and Associates is next.

Good morning.

Morning.

On your Overton Field, how much of it do you believe you'll be able to down space to 40 acre spacing with the data you have now? And what would you suggest as kind of your remaining inventory to drill in that field?

Well, the -- how much would go to 40s is -- is still pretty hard to say, Jeff. You know, the data that we had when we began talking about this was the -- was the four wells that we drilled in '03. And we have not really drilled any other 40-acre wells in '03. We have some in the first quarter here that will be ruled 38-type wells that -- that will be, you know, [INAUDIBLE] 40-acre wells, but, you know, the -- it's hard to say. There is, you know,general there's -- there's kind of say a third or a half of the field that we're kind of focused on that looks like it might have potential to -- to do the -- to do the 40-acre drilling and then there's a part of it that we can kind of exclude from what we know now, you know, it's subject to change, that probably will not need it because the drainage is better. But I think past, you know, past 2004, just looking at all of that and weighing all the evidence, I think we have another, you know, another 70, 80 wells, something in that range still left to do.

I think, and, Richard, I would add to that, just another comment, is it fields like these that -- that one day appear to be fields that you would space at 640 acres some days become 320s, some days 160s. And what you do on the fields with a large resource like this is at the end of the day, tied to the economics of the investment, when you look at it at that point in time. So, everything's subject to change, you know, based upon gas price, too.

Sure, okay. And one last question, in moving your '04 guidance from kind of the 50 to 55 Bcf that we were kind of working with last year to the 47.5 to 50, what were the areas that you probably became a little more conservative on in providing that guidance?

Well, Jeff, I think the overall part of it is has to do with where we began 2004. And, of course we've produced less in '03 and therefore our exit rate out of '03 is less than it was, you know, than we would have anticipated it to be when we began 2003. And those areas, I think we pretty well covered already, south Louisiana being most of it. Some of our Arkoma production was lower because we entered 2003 at a lower rate and some of our projects at the end of '02.

So, I think, you know, that's -- that's -- the starting point becomes the -- the primary driver and, you know, we're, again, happy that -- that we can anticipate a double-digit production growth in '04 given that what we're doing here is all organically driven. We are, you know, we don't plug any acquisitions somewhere along the year to fill -- fill some -- some expectation. And so do you have anything to add to that, Richard?

No, I think that's -- you know, you have that effect -- that you're rolling that number forward into 2004 and there's a couple of Bcf really what we're talking about and if you add that -- those two Bs through our range of guidance that we're giving here, you know, we're back in the 50, 52 Bcf range. So, it's -- that kind of accounts for it.

Okay, great, thank you.

And we'll go to CIBC World Markets, Clayton Van Levy.

Good morning, folks, how are you?

Very good, how are you?

Good, good. Looks like you had a great year. One of the things that I'm looking at and you talked about your PVI focus, Harold, when I look at cash flow divided by DD&A A in 2002 was only 31%, great number in 2003. I computed about 131% and because you -- looks like you've hedged roughly 77% of our production in 2004, I'm coming up a number of about 175%. So, it looks like it's a great trend on -- on an economic basis. Kind of begs the question for 2005. You don't have -- you have some hedges out, looks like about 22%. When would you -- when would you step that up and kind of what is your decision-making process? How does that work?

Yeah, well our thinking on -- on hedging, and we have -- we've talked about this in the past six months this way, is that our 2005, generally speaking, we'd like to be about 50% hedged by mid-year of 2004. So, you know, in most all the hedges we have in place -- well, all the hedges we have in place -- not all of them, but most of what we have in place for '05 right now is fixed price swaps with pretty high numbers on them. The first quarter of the year we have a little bit that we collared and that's just because of the way the spreads are on -- on doing hedges when you're doing them say at the end of '03 for '05. So, short answer is that by mid-year this year, we'd think about being half hedged for '05.

We try to be opportunistic in that and I don't know what more I can say. I guess we would, you know, we'd like to be doing hedging when we have a two-for-one participation on the upside versus the downside, around a fixed price swap when we do those. You know, do collaring.

Okay. Along that line of reasoning and my line of reasoning is, you know, conservative-based company, your PD percentage went up I think what, 84% from 77. Was that a conscious decision, you know, maybe driven by the regulatory environment? Or is it just a function of south Louisiana falling out and kind of looking forward to -- do you have a target range of where you like to keep that?

No, I mean I think mostly what drives us on our reserves is we want to follow good practices on our reserve bookings and, you know, the other thing that we know is that if you -- if you book a lot of proven undeveloped reserves, you know, in a field like Overton you kind of have some choices to make about how many of those future locations you put on the books. You kind of have the same choices to make down there in the Ranger Anticline and we've chosen to be kind of conservative in it. [INAUDIBLE] those areas, book more proven undeveloped locations than we have on the books. But, you know what that happens to you if you do that, the year in which you spend the capital to develop them, you know, you have costs that start to look -- you know, now you're developing something and there's no reserves to add for it. So, we've just been on the conservative side of it.

The reserve bookings that we've had problems with in south Louisiana relate primarily to the problem of trying to understand, when you drill a well in south Louisiana and you have this big, nice pay section that has high [INAUDIBLE] and has a lot of reserves per foot but you drill it to a certain depth and logged pay all the way to the bottom of that sand, it's impossible to tell where the gas water contact is. Is it one foot below the perforation in the well? Or is it 20 feet or 30 feet? It makes a difference and -- and when you -- when you assume that it is a half or one pay section further down dip and then water hits you sooner than you expected, you have reserve write down and sort of -- it's sort of an unavoidable problem. The same sort of problem you face in the Gulf of Mexico, with those very -- where you can put a lot of gas in a few feet.

Okay. And looking at your reserve base now, I guess south Louisiana was -- was the riskier component, more problematic, looking forward, are there any areas that you would be concerned about to have additional write downs? Or do you think it's pretty much cleaned up now?

I think we're in great shape.

We're really good. In fact the -- the downward revision we have is only about 3% of the total and again is -- is most of the activity is we're going for our dollars, as Richard talked about, pretty high percentage allocated to our, you know, lower risk areas, more high probability.

Okay. One mechanical question. Do you have the breakout in terms of cost incurred, you know, on proved -- proved development exploration so we can run our finding costs?

Oh, we have that information, I guess,our -- are you talking about the 10K footnote disclosure?

Correct, correct.

We're in the process of finalizing our 10K and we anticipate filing that on or about mid-week.

Okay.

Next week.

So I will wait on that. The final question, Harold, what -- what concerns you most going forward, you know can looking very the next couple of years and south Louisiana, you know, applaud you for making a, you know, decision not to continue to throw money after something that's not working. What did you learn from that experience and how would that guide you with your new emerging areas, you know, the e-component of your E&P equation?

Well, I think that -- I don't know what, you know, we learned in south Louisiana, is that -- is that it's -- it's an up and down game. We had three extremely good years in south Louisiana. We may have a great year this year in south Louisiana. So, I have a totally given up hope on that.

What I've learned about all of this and it's not anything I didn't know, it's a matter of what projects you have in front of you, say when I'm saying that I'm moving backwards four years and saying gosh, if I would have been born with boardwalk and park place, I would have put hotels on them. The point is as a company we've had to develop opportunities to invest in. We've worked diligently at that. The thing that was directly in front of us four years ago was 3-D data that had begun, or five years ago that had begun to be shot in south Louisiana and we followed through on that, made a pretty good success out of it for a period of three years. But on what I guess I -- what I know overall is that you can't have a big percentage of your capital program going into high history risk, high potential things like south Louisiana.

You know, I think whatever we have done there has been, in retrospect, fine, although it hasn't met our economic perimeters when you sum it up today. We -- we didn't risk a big percentage in the last few years there. And to the extent we have other things that are lower risk, predictable, we're living in a different gas price environment here today than we were, you know, but I still think that as a company, if you're going to be one focused on oar organic growth, you need to have some piece in some higher risk, higher return activities.

So... You know, I mean an example of that is we almost -- sort of we were disappointed in the Permian Basin for a couple of years and now look what we've gotten in this Devonian discovery. The point is you have to keep it back to the highest possible quality and a smaller piece of your capital.

Great, thanks. Good year.

And now we have Michael Scialla with AG Edwards.

Good morning, guys. I guess a follow-up to that on south Louisiana. What percentage -- it sounds like you're looking for partners there. What percentage are you looking to keep in these next couple of wells there?

The -- the one we've got on the horizon is the La range and Duck Lake and we have 50% of that, you know, we're prepared to go forward at 50%. We'd like to kind of get down a little bit more on that, maybe to a third. And then going forward, was I say, you know, the picture is not as clear, but, you know, we're probably looking to be participating more in a quarter -- 25% on other things that we would do.

Okay. And then can you give us your current production rate out of Overton?

Let's see. Hold on one second, Mike. I don't have that on the tip of my tongue. Somewhere 64, 65 million cubic feet per day. Something like that.

That's a gross number, right?

That's a gross number, yeah.

Are you still running the five rigs there?

Actually -- actually we have extra rigs out there right now. It's kind of going to be base loaded as kind of a five-rig program but we will swing some rigs in and out of there during the year. Five rigs won't quite get done what we need, so, at times we're going to have some extra rigs like we do now and then depending on what happens at stockman, you can, we can maybe moving rig back and forth over there.

How many of those are the flex rigs?

Let's see, we've got three of them. Three of them are the H&P's flex rigs.

Great. That's all I have. Thanks.

All right.

We'll move to Kyle Henderson is Imperial Capital.

In 2003, you doubled the capital you directed toward your drilling program. We forecasted 5 to 10% production growth for '03. As late as August of last year, you forecasted about 42 to 44 B and in September you said 42 B in production for '03. Could you give us color on why you came in just about 41 B from last year?

Yeah, I think to repeat what I said earlier, Kyle, the areas -- the two areas that we basically were lower in were the are Kiama basin, which we started the year off lower than we anticipated and south Louisiana as we launched a few wells down there.

Okay.

So the -- the so large part of it t was the -- the three to four B and -- that you lost down in south Louisiana? The combination of the Arkoma Basin and the south Louisiana production, it was under what our plan was.

Okay. All right. Best of luck next year, thank you.

You bet.

And we'll move to Joe Allman with RBC Capital markets.

Good morning, everybody.

Good morning.

Are there any digital opportunities to acquire more acreage in the Ranger Anticline area?

This is Richard, yeah, there is some that we're working at. Don't really want to talk about that geographically, but, you know, there is some.

And then how about just the whole issue of down spacing in Arkansas? Do you see any -- are you working on trying to get approval to down space in other areas outside of Ranger?

No, we don't -- we do not have any filings in right now for other properties. To do that. You know, we'll be looking at the -- it -- at Ranger, you know, as that development goes we'll be looking at, you know, if we're outside that field outline as it is described in the -- in the -- by the commission and that ruling that got us to 80, you know, we'll be looking at, if there's acreage [INAUDIBLE] that that needs to have the -- the 80-acre -- it would be [INAUDIBLE] have the 80-acre spacing, then we'd be looking at that, as well.

Okay. And then just on the new ventures, I guess you've allocated just over $18 million. Does that assume success? Or if you do have some success that might increase?

I -- I think again on that -- that's one of those questions that sort of leads to -- leads to probably areas that we're just not going to discuss, Joe. I mean I --

Got it. Fair enough, appreciate it. Thank you much.

Next we'll go to Ron Mills with Johnson Rice.

Hey, guys, it's Ken Veer. You've pretty much run through the gamma. I did have one question more for Greg. That is if you look at your Cap Ex versus even your projected cash flow, there's a little bit of a -- what, 20-odd million dollar shortfall. Is the thought that you just -- you will look to just go into your revolver, which obviously has a lot of flex flexibility it, I'm just curious -- just philosophically, the thought of pulling down some debt as -- as you move ahead into '04 above and beyond your cash flow?

Ken, you're right on. We would be at net small borrower based occurrent level of prices in '04, although on a capital structure perspective, our debt-to-cap end of the year, about 45% debt to total capital, we would actually improve our debt to capital structure, even if we were a net borrower. So, and of right now our borrowing is -- on that facility, we have a lot of capacity, like you mentioned and we're borrowing at 125 basis points over LIBOR, so, it's at a very good rate.

Absolutely. And I think you just answered the question, you're looking at more of that debt-to-cap as opposed to staying fixed within cash flow, if you -- assuming in -- assuming you've got the projects to -- the -- that fits your perimeters.

That's exactly right.

Okay. Okay. Well, that's great. Thank you, guys. Nice -- nice year to put behind you.

Thank you.

And we have Robert Christianson with Buckingham Research.

If I may, another question or two. The coal bed methane acreage, is it federal, state fee?

It's primarily private.

Okay. And then assuming you have some success -- all of these are very unique, each one is so different. Do you envision or have you contracted with sort of an outside consultant on this? Where did you get, I guess, your and -- and that kind of thing?

Well, we have...

I know Harold is a Colorado School of Mines guy, but ...

We have considerable technical resources to bring the bear on it here internally.

Uh-huh.

And then -- and then also with -- with specialists that we have engaged, so, we feel real good about the technical resources we have to evaluate it.

We worked on coal bed methane before it was cool!

On the 345,000 other acres, is it varying lease links? I mean is it, you know, 3, 4, 5-type year? I mean how long do you have to work on that.

We have as long as it takes, Bob. We have -- we have a lease position that's -- you know, that -- each lease will have its own term in it, but we're right now are in a position of wanting to increase the position we have and the way to do that is quietly.

Okay. Then the next question relates to how much has been capitalized in south Louisiana and not been amortized, you know, if I get ahead of the 10K.

In what is our unamortized pool?

Yeah.

Our un-- what do you call it, undeveloped pool?

Yes, unamortized, capitalized but not being expensed.

That's the south Louisiana --

This is Greg, there's about $11 million in unamortized. I think the total relates to lease holds and seismic and stuff in south Louisiana.

Okay, that's what I wanted. And then if I was to look at the $18 million of new venture spending, is it seismic, drilling, more acreages? I mean are the wells like a well in the coal bed methane and a couple of well pilot,that $18 million -- or is $18 million for really new stuff beyond what you've currently discussed today?

Yeah, we can address the coal bed methane. I think it's $4 million of the $18 million is in the coal bed methane project that Richard's talked about and the other is another part of new ventures.

Okay. Well, thank you very much.

And that does conclude today's question and answer session. Mr. Harold Korell, back to you for additional or closing remarks.

Okay. Well, I want to thank everyone for being with us here today. We're looking forward to another record year in 2004 with the production growth at -- that we think we can see. We're going to have active drilling programs, low-risk type drilling in East Texas and the Arkoma Basin, again. And we'll be moderately active in the Permian Basin to follow-on with some of our -- our projects there. And as we've said earlier, we will be reducing our activity in south Louisiana.

We've also seated some new ideas in 2003 and we're anxious, as you are, look forward to testing some of those in 2004 and beyond that. So, overall we believe 2004 is going to be a very exciting year for our company and the shareholders and thanks for joining us today.

That does conclude today's conference call. Once again, we thank you for your participation.