西南能源 (SWN) 2004 Q2 法說會逐字稿

Good morning, everyone, and welcome to the Southwestern Energy Company's second quarter 2004 teleconference. At this time, I'd like to turn the conference over to the President, Chairman, and CEO, Mr. Harold Korell. Please go ahead, Sir.

Thank you. Good morning and thank you for joining us. With me today are Richard Lane, our Executive VP of Exploration and Production Company and Greg Kerley, our Chief Financial Officer. If you have not received a copy of the press release as we announced yesterday regarding our second quarter results, you may call Pam at 281-618-4809 and she will 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 that involve risks, 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 our control. Although we believe the expectations expressed are based on reasonable assumptions, they're not guarantees of future performance and actual results or developments may differ materially.

To begin with, 2004 is shaping up to be another record year for our Company both financially and operationally. Our financial results were the highest quarter results in the Company's history with net income of 20.8 million and cash flow of 50.3 million, up 119 percent and 76 percent, respectively, over our results in the second quarter of 2003.

Our production continues to grow significantly and our volumes increased 25 percent from this time last year to 12.6 BCfe during the quarter. Our development joint programs in East Texas and the Arkoma Basin continue to create significant value. And our exploration success at River Ridge in New Mexico is contributing nicely to our production volumes.

We also announced last week that we acquired additional working interest in the River Ridge discovery and we've raised our production guidance for the rest of the year. We look for both production reserves to grow substantially this year and expect double-digit growth again in 2005.

We also hope to be in a position to discuss our new ventures activity before year end.

Now, I'd like to turn the conference over to Richard Lane for an update on operations.

Thank you, Harold, and good morning. Production for the second quarter was 12.6 BCfe, up 25 percent from the 10.1 Bcfe we produced in the second quarter of 2003. And up 10 percent from the 11.4 Bcfe we produced in the first quarter of this year. This is the fifth consecutive quarter of production growth for Southwestern Energy.

Production for the first six months of 2004 was 24 Bcfe, up 27 percent from the 18.9 Bcfe we produced in the first six months of last year.

The strong increase in production is primarily attributable to the continued successful development of our Overton Field and increased production volumes from our River Ridge discovery in southeast New Mexico. Of the 12.6 Bcfe of second quarter production by area, 5.4 Bcfe was from East Texas, 4.7 from the Arkoma Basin, 1.3 from the Permian Basin and 1.2 from our Gulf Coast area.

In the first half of the year, we participated in drilling 93 wells. Of these 67 were successful and 19 were in progress at the end of the quarter. On a year-to-date basis, our drilling program has had an overall success rate of 91 percent. In the Arkoma Basin, we participated in 36 wells through the first six months of the year. Of these 22 were successful, 4 were dry and 10 were in progress at the end of the quarter.

We continue to be very active in our Ranger Anticline area in Yell County with some significant developments on our Western exploratory acreage.

In the first six months of 2004, we spudded a total of 10 wells of which 7 were successful, 2 were dry and 1 was in progress. During the quarter we completed construction and put into service the pipeline to the western side of our field and as a result, we now have the Smith, Albright, and Billier (ph) wells on line and they were producing at a combined gross rate of about 6.5 million cubic feet per day.

In 2004, we plan to drill a total of approximately 20 wells at Ranger and since inception, we have completed 33 out of 40 wells drilled, adding 42 net Bcfe, giving us a finding (ph) development costs of 81 cents per Mcfe.

Our drilling inventory also in the areas are continuing to grow. Based on recent results we currently believe that there are at least 30 low-risk locations at Ranger to be drilled after 2004, and an additional 90 locations that are contingent on the drilling success of our current low-risk inventory.

Additionally, earlier this week, we successfully obtained regulatory approval to drill to tighter spacing at Ranger. The new field rules permit us to drill wells within 560 feet of each other. Meaning we will be allowed to drill on closer than 80 acres spacing resulting in a more effective development of the reservoir.

In addition to our Ranger Anticline development, we continue to be active in the main fareway are of the Arkoma Basin. Our Overton Field development program continues on course and it is yielding very good results. In the first half of 2004, we spudded a total of 45 wells of which 38 are producers and 7 were in progress.

We continue to maintain 100 percent drilling success rate at Overton that began in 2001.

Gross production in the Overton Field at the end of the second quarter was approximately 80 MMcf equivalent per day, up from 16 MMcf per day at the end of 2003. We currently have 5 rigs running at Overton and expect to drill approximately 74 wells during 2004.

Our year-to-date wells have taken an average of 22 days to drill with an average IP of 2.9 MMcf per day and an estimated ultimate recovery of 1.8 bcfe per well. Based on our current well performance projections and reasonable gas price assumptions we anticipate that our drilling program at Overton could extend beyond 2006. We estimate that we will have 130 more locations at the end of 2004 under a $5 per Mcfe price environment and the number remaining locations increases to about 187 wells if gas prices average $6 per Mcfe.

In the Permian Basin as we announced late last week, we acquired additional working interest in our River Ridge discovery in Lee County, New Mexico for $14.4 million. This acquisition consolidates our position in this discovery and increases our working interest in the Rio Blanco 041 well from 12.5 percent to 50 percent and gives us a 50 percent interest in the Rio Blanco 43 development well.

The two completed wells at River Ridge -- the Rio Blanco 33 1 and 4 1 are currently producing at a combined rate of 30 MMcf per day.

After the acquisition, Southwestern's total net proved reserves in the fields are approximately 17 Bcfe and our overall finding and development costs for the project is approximately $1.27 per Mcfe.

There are three rigs running at River Ridge currently. Rio Blanco 33 2 has reached total debt and has begun testing and completion operations. The Rio Blanco 4 3 in which we held no interest prior to the acquisition is at about 14,300 feet. And finally the Rio Blanco 9 1 is drilling at 8000 feet.

Southwestern holds a 50 percent working interest in the Rio Blanco 33 2 and 4 3 wells and a 34 percent interest in the 9 1. Each of these wells is targeting the Devonian formation at approximately 15,000 feet.

We currently have three rigs running in our Gulf Coast region, as well. One is an exploration test while the other two are low risk development wells. In South Louisiana we spudded over a L'Orange prospect in our our Duck Lake 3-D shoot during the second quarter. We operate this exploration prospect and it's targeting the Marg A sands at 15,600 feet with a 50 percent working interest.

We are currently at 10,800 feet and expect to be at total depth in approximately 10 weeks. We are also drilling a development well at our Lake (ph) Field in Terrabone (ph) parish. The Apache Fee 15 1 is targeting the Tex W. Sand at 14,500 feet. Southwestern also operates this well which we expect to be at total depth by the end of the third quarter with a 45 percent working interest.

Finally we are drilling a development well in our Seven Sisters Field in Duval County, Texas. We held a 33 percent working interest in the Humble Fee number 9 well which is targeting the Reagan and House Wilcox sands between 11,500 feet and 14,000 feet.

To summarize, as a result of the continued success of our drilling programs in the Arkoma Basin and East Texas and our acquisition of additional interest in our River Ridge discovery, we recently increased our full year 2004 production guidance to between 50 and 52 bcfe. We are well on track to achieve greater than 20 percent organically driven production growth for the year. The Company has had good results in the first half of the year and we are projecting continued strong results in the third and fourth quarters.

We have confirmed considerable additional drilling inventory at both our Ranger Anticline and Overton Field projects which provides clear visibility for continued profitable growth in production and reserves through 2006. And we are investing in new venture areas for future growth.

I will now turn it over to Greg Kerley who will discuss our financial results.

Thank you, Richard, and good morning. As Harold indicated we had a great quarter. Strong commodity prices and a 25 percent increase in production volumes resulted in record second quarter earnings of $20.8 million or 56 cents per share -- more than double our earnings of $9.5 million or 26 cents a share for the second quarter of 2003.

Included in our results for the second quarter was a pre-tax gain of $1.5 million or approximately 2 cents per share on the sale of commercial real estate. Net cash flow provided by operating activities before changes in operating assets and liabilities also set a new record for the quarter at $50.3 million up 76 percent from the same period in 2003.

Net income for the six months ended June 30th was $45.3 million or $1.23 per share, up 95 percent from $23.2 million or 71 cents a share in 2003.

Net cash flow provided by operating activity before changes in operating assets and liability was $106.8 million for the first six months of 2004 up 64 percent from the same period in 2003.

Operating income for our E&P segment was $37.5 million for the second quarter of 2004. Up from $21.5 million for the second quarter of 2003. The comparative increase was primarily due to the increase in our production volumes, combined with higher realized oil and gas prices. Including the effect of hedges, we realized an average price of $5.25 per Mcf for the second quarter of 2004 up from $4.28 per Mcf a year ago.

And our average realized oil price was $28.68 per barrel for the quarter, up from $27.40 per barrel last year.

Going forward, approximately 65 percent to 75 percent of our targeted gas production in 2004 and over 35 billion cubic feet of our gas production in 2005 is hedged at attractive prices.

We have also started to layer in some hedges for our 2006 production. Our current hedged position is detailed in our Form 10-Q that was filed yesterday. Our E&P segment continues to benefit from some of the lowest operating costs in the industry.

These operating expenses per unit of production were 39 cents per Mcf in the second quarter of 2004 compared to 36 cents per Mcf a year ago.

Our general and administrative expense were 2000 (ph) for 35 cents for per Mcf in the second quarter of 2004 down from 40 cents per Mcf in the same period of 2003. The decrease in our per unit G&A expense was primarily due to the increase in our production volume.

Our utility systems realized a seasonal operating loss of 1.4 million in the second quarter of 2004 compared to a loss of 2.1 million for the same period of 2003. The comparative improvement in operating income was primarily due to the effects of the 4.1 million annual rate increase implemented in late 2003. The positive impact of utilities rate increase combined with an increase in the number of customers offset the effects of warmer weather in utility service territory during the second quarter of 2004, which was 16 percent warmer than normal and 6 percent warmer than the prior year.

Operating income for our gas marketing activities was approximately 800,000 for the quarter compared to approximately 500,000 the second quarter of 2003. The increase in operating income was primarily due to the increase in volumes marketed. During the quarter, we realized a pre-tax loss from operations of $700,000 related to the Company's 25 percent interest in the NOARK pipeline compared to a pre-tax loss of 100,000 for the same period in 2003.

The loss in 2004 included adjustments to previous allocations of income and expense by the pipelines operator. Our capital investments for the first six months of 2004 totaled 126.8 million, including 123 million for E&P operations, up from 80.5 million during the first six months of 2003.

As we announced last week, as a result of our acquisition of additional working interest in our River Ridge discovery, we expect our total capital expenditures in 2004 to be approximately 254 million. Up from 239 million previously announced in June. Of the 254 million, 244.5 million is allocated to our E&P segment.

Net cash provided by operating activities was 120.5 million in the first six months of 2004 compared to 70.3 million for the same period in 2003. For the first six months of 2004, cash provided by our operating activities provided 94 percent of our requirements for capital expenditures whereas cash provided by our operating activities only supplied 87 percent of our requirements for the same period in 2003.

Our strong cash flow from operations, coupled with record earnings over the first half of the year, have enabled us to fund our increased capital program which is up 58 percent from last year and still reduce our total debt to capitalization ratio from 45 percent at December 31st, 2003, to 42 percent at June 30th, 2004.

Since the beginning of last year, our stock price has appreciated over 180 percent. And during the second quarter we released $1 billion in market capitalization. Our outlook for the remainder of the year remains very positive and last week, we increased our production guidance for 2004.

We currently expect our production to range between 50 and 52 Bcf equivalent, an increase of 21 to 26 percent over our 2003 production of 41.2 Bcfe. The increase from our prior guidance is due to the increase net production from our recent acquisition of additional working interest in River Ridge and from the continued success of our drilling program.

In the third quarter, we expect our production to range between 12.9 and 13.8 Bcfe. And in the fourth quarter, we expect our production to range between 13.1 and 14.2 Bcfe.

Assuming NYMEX commodity prices of $6 per Mcfe per gas and $34 per barrel of oil for 2004 we are targeting net income to 2004 of 94 to 97 million in net cash (indiscernible) provided by operating activities before changes in operating assets and liabilities about 225 to 228 million. We expect our operating income to approximate 172 to 175 million and our EBITDA to be approximately 242 to 245 million in 2004.

That concludes my comments and now we'll turn back to the operator who will explain the procedure for asking questions.

(OPERATOR INSTRUCTIONS)

Joe Allman, RBC Capital Markets.

Could you talk a little bit about service cost increases that you've seen recently and at what point might you consider slowing activity based on cost increases?

I think just to address our program, Joe, we saw increases in the first half of the year that ranged from 5 percent up to as much as 50 percent depending on what category of course steel related products were the highest. That would be the 50 percent. Going forward if you look at those categories we see in the second half of the year and you have to use a crystal ball a little bit, but we see those categories going up about another 5 percent. A couple of them may be higher than that. But for our program that forecast for the second half of the year is really already built into our program and the capital increases that we announced earlier in the year.

So that's all built into that and we think we can do the program for what we've laid out and everything works very well at these prices.

Joe another way of answering that question is, we built our plan for this year using a $4 NYMEX price. Gas prices as you know are significantly higher than that and our discipline is put to our capital in the project that generate a minimum of 1.3 PVI and at $4 and so at current gas prices I don't see us slowing down capital investments because they're so -- we're in such a return over our cost of debt. And as long as our inventory looks like it does, we're going to be actively drilling.

David Heikkinen with Hibernia South Capital.

Just a question around your plan for '05 and thinking about that, would you still use $4 gas, Harold, for your plan going into '05? Or are you getting comfortable with a higher commodity price?

This is the time of year we begin building our model for '05 and over the next actually over the next few months we will do that. We will start building from the base up and we will have to answer that question and my tendency is, we're probably going to move it up because, otherwise, we are probably passing opportunities we should maybe be taking advantage of in some cases.

I think we are not ready to answer that question yet. But my sense is that we will probably be moving it up. That's something that we will have to discuss with our Board and so on.

And you guys did step out a little earlier with a press release and commentary that you targeted double-digit production growth in '05 and that was still using the same type $4 level. So probably could see some additional upside if you did, budgeting a little higher levels in the next year as you go into this planning process kind of forward thinking regional thought process for us.

I don't think we would go higher than double-digit. That would include three digits.

Higher double digits than just 10 percent, I think.

All we've said is double digits and that's all we're going to say right now until we build our plan because our plan, again, is based on building every project from the base up with an eye to PVI so we are more focused on that than we are including out some growth number.

As you look forward and kind of into the third and fourth quarter with the growth, how much of that is that acquisition in the Permian and how much -- I am trying to remember -- is pure organic? I don't have the numbers in front of me.

The change in the guidance, the upward revision in the guidance is pretty much attributable to about half of it to the acquisition.

Thanks.

(OPERATOR INSTRUCTIONS) Michael Scialla with AG Edwards.

Couple questions on the Ranger Anticline area. What's the regulatory approval now to down space there? Do you have an idea what kind of spacing that will ultimately be developed on? Or can you tell us what you think those wells are draining on average?

Yes Mike this is Richard. I can address that for you. We were at 80 acres spacing as you recall. And felt like that was probably more than the wells would drain but this approval that we have in place here that we just recently obtained allows for us to drill wells within 560 feet of each other. And so the kind of grid system with boxes and acreage spacing units kind of goes away and you go to this program where you can just drill wells within 560 feet of each other. If you just do the math on that you'll come up with the amount of wells you could put in a 640 acre unit is by acre is very low, it's less than 20 acres so it allows for spacing greater than we would likely do. The ruling is more there for us to certainly go below 80 acres but really to optimize where we can put our wells both from a surface restriction standpoint and for geologic reasons. So it's a very variable reservoir there and if you take the approach of just the pure acreage spacing to try to get the well count I think you'll get off. I think if you go by the guidance that we have put out there in terms of the kind of locations that we see -- it's probably the best way to understand what we have in front of us.

So is it safe to say that inventory that you see of 30 low-risk locations and 90 contingent locations could go up with this approval? Or has that already been factored in?

No, it could go up from those numbers.

What the advantage to us is going to be -- people tend to try to think of that structure as simplified as just one big Anticline but you being a geophysicist know it's not that way. Some of the other guys may not but we got multiple thrust sheets. And by having this kind of spacing that we now have approved, it will allow us to optimize that and as we drill more wells we will have as always I say we will know more as we go. But it's a very positive thing. Instead of having to stick just to that 80 acres spacing that we can locate wells efficiently and optimally, I think from a drainage standpoint probably enhanced our ability to drill more there, but we need to go on and drill and this thing will unfold as we go, it will be more clear to us.

Just one more on that area. Do you see any opportunities outside of the immediate Ranger area in that overthrust trend to pick up acreage of this point?

We do have, we do presently hold acreage in the southern part of the basin related to that trend in two different areas. We did some drilling on one last year without success. But we still have some ideas left on that acreage and then we have some other acreage that has yet to be tested.

Amir Arif, Friedman Billings Ramsey.

Couple of questions for you. Just following up on the Ranger Anticline area, the 20 wells you're going to be drilling there this year. Are any of those going to test the acreage to the right of the play? Existing play?

One of those wells is intended and maybe another well are there. We are still getting all that put back together. So yes -- but the answer is yes.

And so the 20 wells you drilled this year, will that help you prove up the 90 other locations you're talking about or will that be needed or do you need to start drilling the 30 other low risk wells before you start proving up those 90?

Well, I think every well we drill gives us more data, Amir, and each successful well has a chance of adding 4 basically around it, is kind of how it works. And so far this thing -- it's going extremely well.

One final question on the River Ridge discovery. Do you see more upside in terms of other pools or other fields that you could discover in the area or is it simply a matter of exploiting the discovery that you think we should work an interest in?

Certainly we got a good development program there on the field itself. And we have some other ideas. Nothing that we have really put together and would want to talk about right now.

One final question if you permit me here. On your hedging strategy going forward, historically, you guys have hedged out a significant portion and definitely in the following (indiscernible) and the year after with improved balance sheet and the strong gas price situation, any change to that strategy in terms of hedging going forward?

I think in general our hedging strategy will be similar to what it's been. We generally tried to be about something like at least 50 percent hedged by the time we get to the calendar year that we are talk about hedging for. And you know, we just recently have put in some hedges which would have been reported at this time that for '06 454s in them and range from $12 ceilings down to $7 ceilings during the summertime. So we just think it's good business to have a portion of our production out there. We do not know what is going to happen to gas prices but we know that $4.50 is a pretty nice floor to have under some of these projects that have predictable results and volume. So we just think it's good business to have a portion of it hedged. And it's not because we're -- of our debt level. It's just the way we think about our business to take -- to have the discipline to take some of the price risk out.

I don't think we're giving up a lot of upside with collars that have $7 in the summer and $11 or $12 in the first quarter.

(OPERATOR INSTRUCTIONS) Edward Min (ph) with Raymond James.

Just wanted to ask whether you can elaborate or provide any new information on new ventures where you're building new acreage positions?

No. We haven't provided any new information on that. And so I can't elaborate on that anything at this time.

Do you think that information will be forthcoming? Can you give us any time frame?

No.

Mr. Korell, at this time I will turn the conference back over to you for any further or closing comments.

Okay, well, thank you all for joining us today. Things are going extremely well as the year is unfolding. Again we have a good inventory of things to drill. And we are looking forward to another couple of very good quarters for the Company and '05 is beginning to shape up for us in our mind as another good year. So thank you for joining us.

That does conclude today's conference call and we thank you for your participation. You may now disconnect.