8-K/A

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K/A
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported)   July 25, 2002
SOUTHWESTERN ENERGY COMPANY
(Exact name of registrant as specified in its charter)
Arkansas	1-8246	71-0205415
(State of incorporation	(Commission	(I.R.S. Employer
or organization)	File Number)	Identification No.)
2350 N. Sam Houston Pkwy. E., Suite 300, Houston, Texas 77032
(Address of principal executive offices, including zip code)
(281) 618-4700
(Registrant's telephone number, including area code)
No Change
(Former name, former address and former fiscal year; if changed since last report)
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Item 7.(c)

Exhibits

            (99.1) Conference Call Summary dated July 25, 2002.


Item 9.

Regulation FD Disclosures

            Southwestern Energy Company is furnishing under Item 9 of this Current Report on Form 8-K the information included as exhibit 99.1 to this report.

Note: The information in this report (including the exhibit) is furnished pursuant to Item 9 and shall not be deemed to be "filed" for the purposes of Section 18 of the Securities Exchange Act of 1934 or otherwise subject to the liabilities of that section. This report will not be deemed an admission as to the materiality of any information in the report that is required to be disclosed solely by Regulation FD.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		SOUTHWESTERN ENERGY COMPANY
		Registrant
DATE:	July 30, 2002	BY:	/s/ GREG D. KERLEY
			Greg D. Kerley
			Executive Vice President
			and Chief Financial Officer

EXHIBIT INDEX
Exhibit No.		Description
99.1	Conference Call Summary dated July 25, 2002.

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EX-99.1 CHARTER

2002 Second Quarter Results Conference Call
Thursday, July 25, 2002
Chaired by
Harold Korell
President and Chief Executive Officer

Korell:     Good morning and thank you for joining us today. If you've not received our press release announcing our second quarter results, you can call Carole Ann at (281) 618-4710 and she'll fax a copy to you. Also, our attorneys have asked that I point out that some of the comments during this teleconference may be regarded as forward-looking statements that involve risks and uncertainties that are detailed in the Company's Securities and Exchange Commission filings. While we believe they are reasonable representations of the Company's expected performance, actual results could differ materially.

As always, with me today are Richard Lane, our Executive Vice President of our Exploration and Production Business, and Greg Kerley, our Chief Financial Officer. But before getting into their presentations, I'd like to make a few comments about the quarter.

Overall, we had a good second quarter. Although drilling activity was low in the first quarter of this year, we were able to maintain our production volumes at 10.3 Bcfe, which is flat with the first quarter and up 5% over last year. Our production has, however, felt the negative impact of less drilling in the Arkoma and restricted producing rates in South Louisiana. On the positive side, our Overton drilling has been accelerated and continues to yield significant economic gain. Richard will discuss these things in more detail.

On the financial front, we suffered a downgrade in our debt rating at Moody's, on the same day that our investment grade rating from Standard and Poor's was affirmed. We again learned the lesson that bad news gets a whole lot more press than good news. This rating process has been frustrating for us this year. The downgrade from Moody's comes at a time when we have made very significant progress in improving the financial strength of the Company. Yes, we realize we're small and that our debt-to-cap ratio is 66%, but our target of adding $1.30 to $1.50 of value for each dollar we invest in our E&P operation has been moving us in the right direction.

Consider the following comparisons of our current position to that when we were rated last in January of 2001:

• Our debt-to-capital ratio at that time was 74%. It's now 66%.
• We've grown our production organically by 11% in the same time frame.
• Our finding and development costs excluding price related revisions for 2001 was $1.11 per Mcfe.
• Our interest coverage ratio was 4.5 times. It's now 5.7 times.
• Finally, we believe that cash flow is the most important measure of a company's financial viability and this is where we stand out. Our cash flow per unit of production is greater than many other higher-rated companies due to our lower cost structure and the high quality of our reserves.

But putting that behind us, the real effect of the downgrade, as Greg will discuss, is immaterial to our ongoing financial picture. It just doesn't feel good.

To sum up, overall I am pleased with our second quarter but we realize we have to keep working hard to stay ahead. We have an active third quarter planned in continuing our strategy of adding value with the drill bit. I'd like to now turn the presentation over to Richard Lane for an update on our E&P operations and then to Greg Kerley for comments on the financial results for the quarter.

Lane:     Thank you, Harold, and good morning to everybody. Our activity picked up in the second quarter of this year. In total, we participated in 19 wells that were spud in the second quarter, as compared to 13 for the first quarter. Of these 19 wells, 12 were successful and three were in progress at the end of the quarter. Production for the quarter was 10.3 Bcfe, up from 9.8 Bcfe in the second quarter of 2001 and equivalent to the first quarter of this year. In the Arkoma Basin, we spud 11 wells in the second quarter as compared to two in the first quarter of this year. Of these, seven were successful and four were dry.

Two successful wells of note are within our legacy Fairway area on the Arkansas side of the basin. The Grimmer #1-17 well located in Johnson County tested 10.7 million cubic feet of gas per day from Hale perforations at approximately 4,100 feet. This well is operated by Southwestern with a 98% working interest and is currently producing 6 million cubic feet of gas per day. The Tolton #1-17 is a Southwestern-operated well located in Franklin County. We hold an 82% working interest in this well that is currently producing at 2 million cubic feet of gas per day from the Casey sand at 2,950 feet. In addition to our drilling activity in the Arkoma, we have continued to aggressively pursue our workover program. We have completed 22 workovers to date in 2002, resulting in a net production increase of approximately 6 million cubic feet of gas per day.

One example of our workover success is the stimulation of our Hayes #1-23 well in Johnson County. Gross production from this well, which we operate with an 81% working interest, increased from 125 Mcf per day to 1.3 million cubic feet per day. Because of our continued success in this area, we have recently deployed a second rig to accelerate our workover program in the basin.

In the Permian Basin, we drilled our first horizontal well at our Birds of Prey prospect in Eddy County, New Mexico. The Peregrine #1 well, which is completed in the Cherry Canyon horizon at 4,850 feet, had a 1,390-foot lateral. Based on mud logs, we estimate that we exposed approximately 700 feet of well-developed oil pay. We operate this well which tested at 100 barrels per day and three barrels of water, and with a 100% working interest. We'll be watching this well's performance carefully, as Southwestern has approximately 1,900 net acres immediately offsetting this well for potential further development.

At our Overton Field in Smith County, Texas, we have drilled and completed seven wells year-to-date including two wells on our South Overton acreage. We continue to realize significant reductions in drilling costs at Overton. Current costs are approximately 25% lower than they were in 2001. As I mentioned last time, we have mitigated the risk of much higher drilling costs in the near term by forging agreements with several of our primary vendors. By the end of 2002, we expect to drill up to 18 wells at Overton. Southwestern operates these wells, which are targeting the Cotton Valley sands at about 11,800 feet, with an average working interest of 98%.

To further expand our activity in East Texas, we are currently negotiating on 3,300 net acres of land offsetting some recent Travis Peak and Cotton Valley development in Anderson County. This acreage is located approximately 50 miles southwest of our Overton operations. While this block is undeveloped at this time, we see the potential to apply the technologies that we've refined at Overton to this prospect. We anticipate that the first well on this area, which we call Cayuga, will be drilled in early 2003.

Additionally in Texas, we successfully completed our Mustango prospect in May. This well located in Nueces County, is producing 1.6 million cubic feet per day from the first of six Frio sands that we have found there. Southwestern operates this discovery with an 80% working interest.

In South Louisiana, we are drilling an exploratory test on our Bushmills prospect in Iberia Parish. In early July, we had to sidetrack the Peterman #1 well due to some mechanical problems we experienced, but we anticipate reaching total depth on this well within one month. Southwestern holds a 70% working interest in the Bushmills prospect.

Our next South Louisiana exploratory test that we will drill is our Piedmont Prospect located in Vermilion Parish. This well is targeting the Alliance Sand at 12,700 feet and should be spud during the third quarter. Southwestern will operate this well with a 62.5% working interest. Additionally in South Louisiana, we plan to participate in two wells in our Cameron Prairie project during the third quarter.

We are continuing data acquisition on our 140-square mile Duck Lake 3-D project located in St. Mary and St. Martin Parishes. We're approximately 50% complete shooting this project that's adjacent to some previous successful areas for us. We expect the seismic data to be delivered for interpretation by the end of the year, and that this shoot will lead to several other prospects that we can begin to test in 2003.

As Harold mentioned, we have curtailed some of our South Louisiana production in recent months. In particular at our North Grosbec field, we have experienced some water production from our two wells, the Brownell-Kidd and Raymond Egle. These two wells are still currently producing at a combined rate of over 28 million cubic feet of gas per day and 950 barrels of condensate per day, but have previously been as high as 40 million cubic feet of gas per day and 1,400 barrels of condensate. While these two wells have already had cumulative production of over 18 Bcfe, the water production we're experiencing is earlier in the productive life of the reservoir than we had anticipated. We're currently running a series of production logs on these wells to delineate the source of the water, and some of the early indications are that we may have the opportunity through some remedial well work to eliminate some of that water production.

Finally, we are currently marketing our Western Oklahoma properties. We are following our stated strategy to ultimately sell or trade these assets. We believe that the market for these properties is strong and that this is an opportune time to monetize them.

In summary, we are pleased with the results of our year-to-date 2002 E&P program. We have a strong inventory of projects in the Gulf Coast area, the Permian Basin, the Arkoma Basin and East Texas that we will continue to pursue towards future growth. Through the first half of the year, we have achieved good economic results for our capital invested and are optimistic we can achieve meaningful reserve adds and production growth while holding the line on our operating expenses. I'll now turn the teleconference over to Greg Kerley who will discuss some of the Company's financial information.

Kerley:Thank you, Richard, and good morning. As Harold indicated, we were pleased with our financial results for the quarter and year-to-date. Our results in 2002 reflect continued growth in production volumes, but were heavily influenced by much lower commodity prices. We reported net income of $1.8 million, or $.07 cents a share for the second quarter which compares to $6.9 million, or $.27 cents a share for the second quarter last year. Cash flow from operating activities before working capital changes was $17.4 million during the quarter compared to $25.1 million from last year.

Operating income for the exploration and production segment was $10.1 million during the quarter, down from $18.3 million for the same period in 2001. We realized an average gas price of $2.96 per Mcf during the quarter, down 29% from prices a year ago. Going forward, our gas production for the remainder of this year is approximately two-thirds hedged at an average Nymex floor price of $3.14. With commodity price increases that we saw in late April and early May, we were able to hedge an additional 10 Bcf of production for 2003, bringing our total hedged volumes for 2003 to approximately two-thirds of our expected production. The average Nymex floor price for our hedged production is $3.28 per Mcf in 2003. Our detailed hedge position is included in our Form 10-Q.

Our E&P segment continues to benefit from low operating costs. Lifting costs on an equivalent unit of production basis were $.42 per Mcfe for the quarter, down from $.44 per Mcfe for the second quarter of 2001. Our G&A expenses were $.28 per Mcfe for the second quarter, down from $.54 per Mcfe cents in the second quarter of 2001. Depreciation, depletion and amortization expense for the E&P segment rose during the quarter due to higher production volumes and a higher amortization rate. Amortization rate for the full cost pool for the first half of this year averaged $1.16 per Mcfe compared to $1.09 per Mcfe in 2001.

Our utility experienced a seasonal operating loss at $1.7 million in the second quarter compared to a seasonal loss of $800,000 for the same period last year. The decrease in operating income was due to comparatively higher operating costs experienced during 2002. Operating costs in the second quarter of 2001 were comparatively decreased as a result of a favorable settlement of open issues with the Missouri Public Service Commission related to the Missouri utility assets we sold back in 2000. As we previously stated, we are planning to file a general rate increase for our utility later this year to improve our returns. The Company's marketing operations added another $500,000 of operating income during the quarter compared to $400,000 for the same period last year.

Interest expense decreased 12% for the second quarter of 2002 due to lower average borrowings and a lower average interest rate. During the first six months of 2002, the Company's total debt decreased by $5.5 million. And as Richard mentioned, we are currently marketing our Mid-Continent properties and plan to reduce our debt further with a portion of any proceeds from the sale.

As Harold indicated, we received some disappointing news in early July when Moody's downgraded our public debt from Baa3 to Ba2, at the same time that Standard and Poor's reaffirmed our BBB credit rating. The Moody's action was very disappointing due to the fact that during the past year we made significant improvements in both our operating and financial results, including our ability to service our debt. During 2001, our total debt declined $46 million and all of our key measures and ratios indicating our debt protection capabilities improved. One positive is that the current effect of the downgrade on our interest cost is pretty immaterial, as it only increases the borrowing cost of our revolving credit facility by 12.5 basis points. At the end of the second quarter we had approximately $120 million borrowed under that facility.

Our capital expenditures for the first six months of 2002 totaled $40.8 million including $37.8 million invested in our exploration and production operations. That concludes my comments and we'll turn back to the operator. He will explain the procedure for asking questions.

Questions and Answers

1.     First, I want to congratulate you for hedging because it looks like you've locked in some pretty good returns and I guess that would form my first question regarding your low-risk drilling at Overton. What kind of rates of return do you get for individual wells there and how many additional wells do you have to drill there including the downspacing?

Kerley:     What we have done, as you have indicated, is lock in a very attractive return there. Our hedges are not individually identified by area, but incrementally when we went out and locked our costs on the drilling side for the rest of this year, we hedged the expected production from that drilling at about $4.00 per Mcf - which locked in a PVI for us of over 2.0 to 1.0, or about a 45 to 50% rate of return.

We're tickled to death with that obviously. The program this year, as we continue to drill it, we could drill up to 18 wells, including 15 wells in the main Overton field and three wells in the farm-in acreage that's down south of that. But the 15 wells would still not quite get us down to 160-acre spacing. We'd still have to drill a few more wells to be able to get to that level.

2.     And then to get down to 80-acre spacing what do you need to do for that?

Kerley:     We would have about another 65 wells that would need to be drilled for that.

3.     And do you have approval for 80-acre spacing now?

Lane:     It would be an administrative thing we would have to go through, but we don't anticipate any problems with doing that.

4.     Yes, I'm looking at your presentation. It looks like on 80-acre spacing you can drill about 125 locations. When you downspace, do you get a little less reserves per well? But given these prices, you know in the $3.00 price range, you can maintain rates of return in excess of 30% there I assume?

Lane:     What we know and what we've seen in the other wells is that at 80 acres we should still achieve the same kind of wells in terms of their production and their ultimate recoveries and, hence, those same returns.

5.     So, if I'm looking at this right, as long as you've hedged a locked-in decent price, this is just a manufacturing machine for the next couple of years?

Lane:     Well, I think that's a good way to describe it. We've certainly de-risked the geology part of it, and then we're enhancing the engineering part of it, the factory part of it, as you would say.

6.    From an exploration standpoint, could you articulate a little more on the last couple of wells you talked about in Cameron Parish. On the Piedmont, could you give us the sense of reserve potential, key risks and just give us the scope of it and maybe just give us the names and your thoughts on the two additional Cameron Parish wells? Also, some idea on the drilling costs there, gross dry holes costs per well.

Lane:     Piedmont is a well that we'll be operating. Like I said, it should spud during this quarter and we think it has about a 25 to 30 Bcfe potential, so our net on that would be about 16 to 18 Bcfe. It's in our old Henry 3-D seismic area, so we're pleased to develop an opportunity in there that we think is very attractive and so we'll be pursuing that. I think that will be about a $2.5 million dry hole cost well. And you mentioned the risk; it's a little bit less risky than some of the tests we do, but we still have some risk of structural complexities.

The Cameron Prairie projects that I referred to, those will be operated by Ballard and we'll have about a 30 percent working interest on those. The first one has spud. It's called our Middle Chenier prospect and on a gross basis it has about 45 Bcfe of potential. The second one that will get started in the Cameron Prairie area will be our West Grand Chenier prospect. That's a Big hum target, a little bit shallower and only about a 7,000 foot well, and that's about a 15 Bcfe potential prospect gross. The Middle Chenier well will be about a $2.5 million well and West Grand Chenier will be a little bit under $2 million.

7.     Finally, on the property sale, can you give us a sense of the number of reserves, impact to production and rough range of prices you're looking for, please? And do they have high operating costs? Would you be the beneficiary if you did sell them?

Kerley:     As we indicated, we just started marketing that. What the reserves were at the end of last year were around 35 Bcf equivalent for those properties. The current production is about 4 million cubic feet of gas per day and about 380 barrels of oil a day. They are higher operating costs than what our other properties are and the rest of our portfolio, for sure. But they are properties that are longer-lived generally. We have, as you know, been harvesting those assets for the last several years and were willing to trade those for other core areas, but it makes sense to us to go ahead and harvest that now, especially while we have a place like Overton where we could re-deploy a portion of those proceeds.

8.     Well, congratulations and particularly on the hedging. You know it's nice to see that some people in the patch are running this as a business.

Kerley:     Well, we appreciate the compliment. We are definitely focused on running it as a business and, as Harold indicated, our key driver has been adding value for every dollar we invest and while we've been focused on that, everything else seems to fall in right behind that.

9.    Just an update on what your production is going to be for the rest of the year?

Lane:     Well, we've given some guidance on that in the past, somewhere between 41 and 43 Bcfe for the year, which would be organic growth over last year and we still feel like we're in that range and should be able to achieve a good number there.

10.     Just a couple of questions in terms of the size of the Bushmills project that you're drilling right now - what the potential size for that is and also especially with the sidetrack, what the estimated costs are on that?

Lane:     We see Bushmills as about a 40 Bcfe gross reserve potential prospect. Our net would be about 20 Bcfe of that. We won't know exactly what the full cost of the mechanical problems we have had there, but I would say we're looking at certainly something in excess of $1 million to make that well reach total depth and get it evaluated, above what we had originally estimated.

11.     And what was your original estimate on the cost?

Lane:     I don't have that sitting here right in front of me but we can get that for you.

12.     And then in Nueces County, can you just review the well that you talked about, the one that's producing from the first of six Frio sands? The name of it and if you have additional projects in that area?

Lane:     That's our Mustango prospect. It's on acreage offsetting some HBP acreage we have down there in Nueces County. We had one other producing well nearby. We drilled an offset block there, a fairly shallow test typical of the Frio in that part of the world and it's producing about 1.5 million to 1.6 million cubic feet per day and we have several of these Frio sands behind pipe that will be producing and moving up the hole. And I think there's the potential for maybe one other well on those combined assets that I just talked about.

Korell:     That's not an area that we took off in a new way to get a position in down there. That was an area where we had a producing well and in going through our assets and mapping, we found the opportunity there that we could drill another fault block. So, basically, it's kind of an isolated little project but a nice one to add to what we're doing.

13.     In terms of the rate increase filing, it sounds like you will try to do that later in the year. How long of a process is that? Secondly, in terms of some of the other guidance, production guidance was answered just a second ago, but on the cost side, are the second quarter cost levels pretty indicative of what you expect for the rest of the year?

Kerley:     You're right. I'll answer the cost side first, we expect those to continue where they are, at about the level that we ended up in the second quarter. On G&A and other costs, very similar, so I think the per unit costs that I discussed in my comments and that we have in our press release information will be good ones to use kind of for the balance of the year.

On the rate increase filing, it is a time consuming process. We will file this Fall, but the way the Regulatory Commission works in the state of Arkansas, the Commission has up to a 10-month regulatory period to review your filing and file testimony. So, generally, you see very rare exceptions where you are able to put rates in effect before that ten month filing period, because that's a statutory authority that they have. So, we would look at the second half of next year, but well before the winter period we'd be able to have new rates in effect.

14.     In terms of your cap ex, is the plan still to spend somewhere in the $75 million dollar range for the year?

Kerley:     That's correct, except that as we've indicated before with the sale of the Mid-Continent. Total cap ex is actually $78 million, and that includes $71 million for E&P and about another $7 million for utility and other corporate dollars. But, as we've indicated with the sale of our Oklahoma properties, any proceeds that we have there may increase our capital spending and predominantly in the Overton area.

15.     And in terms of drilling and completion equipment and services in that area, is that available where if you sell those properties you wouldn't have any problem ramping up your Overton program?

Lane:No. There's availability there and we wouldn't anticipate that being a problem.

16.     Regarding the debt situation and debt rating particularly, you indicated that it's kind of immaterial, but in your discussions with Moody's, did they indicate at what level of debt - like was it 60 percent as opposed to 66 percent - that that they would reconsider the rating? And the sense I'm getting is, if we were significantly larger in size with the same debt-to-equity ratio, Moody's results might have been different?

Kerley:They indicated that there are a lot of different factors that are involved in the rating process, and so they would not commit on what particular levels of any particular ratio that you would have to have for a particular rating, which is a little confusing from our standpoint as to what targets we need to be trying to achieve. But again, from our standpoint, it's a very frustrating process from the same points that we made before, in that we have been moving in the right direction I think at a very good pace. And from a credit standpoint, in everything that the rating agencies used, we are significantly better off than we were last year and in the last two years.

On the size issue, it's something I just couldn't say. They indicated that it's a process, at least as they described to us, that involves a lot of different factors, but it is true that we are smaller in size than a lot of the other investment grade-rated companies.

17.     One other question about deal flow and property flow in this market. What are you seeing on the exploratory side? Clearly you're doing this Duck Lake project and you've been very good about promoting projects. Has there been any diminution or slowing down to get some interest on the exploration side of the business? Secondly, on the deal flow side for property acquisitions particularly in your core areas, are you seeing any reductions in pricing expectations or higher deal flow?

Lane:     On the exploration side, and you refer to Duck Lake, of course we have our built-in partners there and are real happy with who we have there to work with. So, in some ways, the deal flow is kind of built in, in that as we develop things we foresee the partners participating so we are able to have good cycle time on those prospects. On the things that we don't have built-in people participating, we're always marketing a few prospects, but I haven't seen it slow. I think over the last twelve-month period it's been about the same. We'd like to see it a little bit higher just to make that easier for that to happen when we're looking for partners, but I think it's been about the same over the last twelve-month period from what I see.

On the A&D side, I don't see a big change this year over the second half of last year in terms of the flow of those properties. There's still a good appetite for them on the acquiring side we believe and, in particular, in the area that we have something on the market in the Mid-Continent area, seems to be pretty good and one of the better areas really to be doing some of that.

Kerley:     Thank you for joining us today and feel free to call me or Brad Sylvester with any other questions you may have or for other information you may need. That concludes the teleconference.