WASHINGTON, D.C. 20549

                                FORM 8-K

                              CURRENT REPORT

                  PURSUANT TO SECTION 13 OR 15(d) OF THE

                     SECURITIES EXCHANGE ACT OF 1934

         Date of Report (Date of earliest event reported) May 1, 2001

                        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)



Item 7.(c)

Exhibits                                                              Reference

        (99.1)   Conference Call Summary dated May 1, 2001.           p. 3 - 12

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.


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

DATE:    May 2, 2001                           BY:   /s/ GREG D. KERLEY
     ------------------                        ---------------------------
                                                     Greg D. Kerley
                                                 Executive Vice President
                                               and Chief Financial Officer

                                      - 2 -

Southwestern Energy                                            Conference Call
Company                                                        Summary

                   2001 First Quarter Results Conference Call

                              Tuesday, May 1, 2001

                                   Chaired by

                                  Harold Korell

                      President and Chief Executive Officer


         Good  morning and thank you for  joining us today.  With me are Richard
Lane, our Senior Vice President of Exploration and Production,  and Greg Kerley,
our Chief Financial  Officer.  After some  preliminary  comments,  I'll turn the
floor over to Richard for an update on our E&P  operations  and then to Greg for
comments on our financial results. After that, we'll be available for questions.

                  If you've not received a copy of the press release  announcing
our first quarter  results,  you can call Carole Anne 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  which are  detailed  in the
Company's Securities and Exchange Commission filings.  While we believe they are
a  reasonable  representation  of the  Company's  expected  performance,  actual
results could differ materially.

                  Now to a discussion of the first quarter. 2001 has started off
with very good  results.  I'm  pleased  with the  continued  progress of our E&P
program and, in this  commodity  price  environment  we're  anticipating  strong
results for the rest of the year.

                  Financially,  we had a tremendous quarter. Our earnings in the
first quarter alone  represented over 75 percent of our total earnings in all of
2000.  Pricing  has  helped  the  entire  industry,  of  course,  but we're also
executing our strategy with the drill bit, which is resulting in higher earnings
and cash flow. In fact, our cash flow in the first quarter has allowed us to pay
down a good portion of the debt we incurred last summer.

                  We'll  continue  to focus on  reducing  our debt level and, at
current  prices,  are  positioned  to pay  down  approximately  $70  million  in
long-term  debt by year end.  Overall,  I'm very pleased with the first  quarter
results and I urge you to keep an eye on our results for the rest of the year.

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                  This is not the  old  Southwestern  Energy  that  some  people
remember.  We're  focused on continuing  the momentum  we've gained with our E&P
strategy and we're very serious about adding value for our shareholders.

                  That   concludes   my   comments   and   I'll   now  turn  the
teleconference over to Richard Lane for an update on our E&P operations.


                  Thank you, Harold,  and good morning.  In the first quarter of
2001,  we continued to build on our success from last year with active  drilling
programs  in  the  Arkoma  Basin,  Gulf  Coast  area,  and  our  Overton  field.
Additionally,  we have drilled  several  successful  wells in our Permian  Basin
program  and are  currently  drilling  on our first of several  South  Louisiana
prospects planned for this year.

                  Production  for the quarter was 9.0 Bcfe,  up from 8.7 Bcfe in
the first quarter of last year and our  production  rate at the end of the first
quarter was 105 million cubic feet equivalent per day and this is our highest in
over two  years.  In total,  we  participated  in 30 wells that were spud in the
first quarter.  Of these,  15 were successful and 10 were in progress at the end
of the quarter.

                  We continue  to create  value with our Arkoma  Basin  drilling
program.  In  the  first  quarter,  we  spudded  13  wells.  Six of  these  were
productive,  three  were dry and four were still in  progress  at the end of the

                  At our Haileyville prospect in Pittsburg County,  Oklahoma, we
continue to be successful.  Last quarter,  you'll remember,  I mentioned that we
had just logged our Agnes #1 well in this trend,  and I'm pleased to report this
well is now on  production  and flowing over 20 million  cubic feet per day. Our
working interest in this well is 37 percent.

                  This brings our Haileyville  area production to  approximately
31  million  cubic feet per day from these  Atokan  age sands  reservoirs  we're
targeting.  Our  interest  in these  wells  range from 32 to 49 percent  and our
latest well in the area, the Cope #3, was spud last week.

                  In  addition  to our  drilling  program,  we've  expanded  our
workover  program in the Arkoma  Basin to  capitalize  on the  current  high gas
prices.  Two recent  successes here have been our Ozark Townsite and our Goznell
wells. We fracture stimulated these old wells and have seen production increases
of 2.2 and 1.8 million cubic feet per day. These projects are delivering five to
10 fold  production  increases for us and rapid project  payouts.  We anticipate
performing 10 to 15 additional  workovers in the Arkoma region during the second

                  Going to the Permian Basin,  we were successful in discovering
new  reserves in four out of the five  exploration  wells that we drilled and we
completed five out of 10 wells overall in the first quarter, with three still in
progress. Our exploration focus continues to be primarily in the Delaware Basin,
targeting Devonian oil and Atokan-Morrow gas objectives.

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                  Acreage  from  our  previously  announced   exploration  joint
ventures with Phillips Petroleum and Energen Resources in Lea and Eddy Counties,
New Mexico,  continues to be a key exploration asset and a valuable resource for
us for  generating  new drilling  opportunities.  In the Permian,  we anticipate
drilling and evaluating three to four additional wells in the second quarter.

                  At our Overton  field in Smith  County,  Texas,  the first two
wells  drilled  and  completed  in  our  in-fill   drilling   program  are  very
encouraging.  The Arnold Gas Unit #1-2, which has been on production since March
15th,  is  producing  currently  at about 1.8  million  cubic feet per day.  The
Kickapoo Gas Unit #1-2 has been on  production  approximately  15 days and it is
producing  about 2.7 million  cubic feet a day.  Now,  while these two wells are
early in their  productive life,  their  performance is currently  exceeding our
pre-drill expectations. Utilizing a two-rig program, we're currently drilling on
additional wells at the Ware 1-2 and Allred 1-2 locations.

                  As we stated at the time we acquired this property, we see the
immediate potential for 15 development  locations,  with future potential for up
to 25 to 30  additional  wells.  We've also expanded our position in the Overton
area through a farm-in of  approximately  5,800  adjacent  acres that includes a
drilling  commitment for this year and the potential for five to 10 locations on
that acreage. In addition, we're negotiating with a potential partner that would
allow for a more accelerated  development plan than originally budgeted for this

                  In South Louisiana,  development operations have progressed on
our earlier discoveries. The State Lease 16625 #1 development well on our Malone
discovery  was  successfully  completed  in  the  Marg  A  sand  at a  depth  of
approximately  12,500 feet.  This well is currently on  production  at a rate of
15.1  million  cubic feet a day and 175 barrels of  condensate  per day,  with a
flowing  tubing  pressure of 4,000 psi.  Southwestern  operates the Malone wells
with a 33 percent working interest.

                  Additionally,  we spud our first development well on our North
Groesbec discovery.  The Norman Breaux #1 is currently drilling at approximately
7,500 feet on its way to a total depth of 20,900  feet.  This well will  further
develop the P-10 sand currently  producing in our discovery well,  which was the
Brownell-Kidd  #1, and that well's  producing  16.4 million cubic feet a day and
583 barrels of  condensate  per day. The Norman  Breaux well will also test some
shallower additional objectives not seen in the Brownell-Kidd well.

                  Exploration  drilling is in  progress at our Mahone  prospect,
located in Vermilion  Parish.  This well is currently  drilling at approximately
13,000 feet. The Mahone prospect, with over 100 Bcfe of gross unrisked potential
is  targeting  Miocene  Age  Discorbis  and Cib Jeff  sands and is planned to be
drilled to a total  depth of 16,100  feet.  We  operate  this well and have a 50
percent working interest.

                  Our next  exploration  well will be our White  Horse  prospect
located in Cameron Parish. We also operate the Whitehorse prospect well and have
a 57-1/2  percent  after-casing-point  interest.  Total  depth  of this  well is
projected  to be 13,100  feet and will be  targeting  Planulina  Age P-2 and P-3
sands,  which have proven to be quite prolific  around the trend.  We anticipate

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spudding  Whitehorse in approximately 30 days.  Finally,  in the South Louisiana
area,  we expect to spud an  exploratory  well on our Horeb  prospect  in Acadia
Parish late in the second quarter.

                  Overall, we're pleased with the start to our 2001 E&P program.
We continue  to  experience  increase in  drilling,  completion  and  production
operation  costs,  as are other  operators.  We can,  however,  continue to help
offset these  inflationary  costs and reach our  production  reserve  targets by
optimizing  the  selection  and the timing of our capital  investments  and also
leveraging  off the  advantage  we have in our  ability to  internally  generate
desirable prospects.

                  The success of our drilling program is critical to growing our
production  rates and to that end, we continue to maintain a strong inventory of
drilling prospects in our core areas to meet these needs. Our overall results so
far this year are in line with our original  projections and we believe that our
production target of 38 Bcfe for the year is attainable.

         I will now turn it over to Greg Kerley,  who will discuss the Company's


                  Thank you, Richard, and good morning. As Harold indicated,  we
had a very strong first  quarter and made good progress on improving our balance

                  We  reported  net  income of $16  million or 64 cents of basic
earnings  per share for the  quarter,  up 74 percent  over the same  period last
year.  Cash flow from operating  activities  before working  capital changes was
$38.6 million during the quarter, up 47 percent from the first quarter of 2000.

                  Our  improved  results  were driven by both  higher  commodity
prices  and  increased  production.  Operating  income for our  exploration  and
production segment was $22 million,  up from $8.7 million for the same period in
2000.  Commodity  prices  were very  strong in the  quarter,  as we  realized an
average gas price of $4.48 per Mcf,  nearly $2 per Mcf higher than our  realized
price for the same period in 2000.

                  We  continue  to be about 80  percent  hedged for our 2001 gas
production  target and there has been no change in our hedge  position since our
press release on December 7th.

                  Operating expenses for the E&P segment rose during the quarter
due  to the  industry-wide  increase  in  costs  related  to  normal  production
activities.  Lifting  costs on an equivalent  unit of  production  basis were 51
cents an Mcfe in the  first  quarter  compared  to 38  cents  an Mcfe the  first
quarter of last year.  Higher oil and gas prices also  affected  our  production
taxes as they increased to 23 cents an Mcfe compared to 13 cents an Mcfe for the
same period in 2000. We anticipate  that our operating costs per equivalent unit
of  production  will remain close to their  current  levels for the remainder of

                  Depreciation,  depletion and amortization  expense for the E&P
segment was also up in the first  quarter due to our higher  production  volumes
and a slightly higher  amortization  rate.

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Amortization  rate for the  full cost pool in the  first quarter  averaged $1.08
per Mcfe compared to $1.03 in the prior year first quarter.

                  Our gas distribution  segment continued its steady performance
with operating  income of $9.4 million in the first quarter,  which was equal to
the level of operating income in the first quarter of 2000, when you exclude the
impact of our Missouri utility properties that were sold in May of last year.

                  Our energy  marketing  efforts also  provided  $1.1 million in
operating income during the first quarter of 2001,  compared to $1.0 million for
the same period last year.

                  Interest  expense in the first  quarter of 2001 is up about 41
percent from the first quarter of 2000 due to our  increased  debt level related
to funding the Hales judgment last year. We are, however, extremely pleased with
the amount of debt  we've  been able to pay down since the end of last year.  In
fact, as of April 30th, we've reduced our debt by approximately $46 million and,
as  Harold  indicated,  based  upon  the  current  level of gas  prices,  we are
positioned to pay down as much as $70 million of debt during 2001, which in turn
should have a positive effect on our stock price.

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

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                              Questions and Answers


1.            Can you talk  about the size  of the Haileyville  prospect and how
              much you had booked at year end in that prospect?

Lane:         The  Haileyville  prospect  is  really a trend  for us that  we're
              developing. We developed a good part of it last year and then this
              activity  we're  talking  about in the first quarter of this year.
              You know,  on a gross  basis out  there,  we've  booked  somewhere
              around 23 to 24 Bcf for all the wells.  That's net of about 6 to 7
              Bcf for us.

2.            What is your expectation of the size of that prospect?

Lane:         Well,  we have more drilling that we have planned for this year in
              the trend,  two to four wells and the higher rate wells that we're
              seeing here are certainly anomalous.  But you know, we need to get
              a little bit more  productive  life to them before we really state
              anything higher than what we've got recorded right now.

3.            Greg  mentioned  the guidance for LOE and  production  taxes going
              forward,  G&A was down  pretty  nicely,  at least on a unit basis.
              What kind of level of G&A do you expect going forward? Is it still
              the guidance you gave in December or do you expect it to be lower?

Kerley:       I  think  the  guidance  we  gave  in  December  is  still  fairly
              reasonable.  Some of the G&A is probably just timing,  but we have
              started  the year on a  favorable  note for that area and with the
              other  costs  we  have  that  are  increasing,  just  inflationary
              pressures,  it's nice that we're able to hold the line pretty good
              there. But I would still go with our targets.

4.            When would you expect the Malone well to be on production?

Lane:         It currently  is on production  at the rate of  15.1 million cubic
              feet a day and 175 barrels of condensate.

Korell:       You might have  thought that  was the rate  of the first well, but
              that's the second well.

5.            When do you expect the first one to come on, then?

Lane:         It's also on  production.  It's  producing a little over 3 million
              cubic  feet a  day,  about  50  barrels  of  condensate  and  some
              associated water, six to seven hundred barrels of water. That well
              is producing  from the first of five zones.  You'll recall that we
              discovered out there, a center zone-- the first  completion at the
              base of the well,  a center  zone and don't have a lot of reserves
              booked  to  that  zone,  but  we're  trying  to eke  out  all  the
              production we can out of that zone before we move up the hole.

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6.            Is that producing as expected?

Lane:         I would say  on the order  of what we  expected.   It was a Bcf or
              less of gross  reserves here  that we were  looking at, so I think
              for  now it's  within the  range of  our  expectations.   The real
              reserves and rates are to be had in the next zone up hole.

7.            Have  you've  taken the excess  cash flow that you've been able to
              generate because of higher gas prices and oil prices and committed
              those funds to debt  paydown as opposed to letting  Richard have a
              few extra  dollars to continue to show good  results?  How are you
              working internally with these excess funds?

              Separately  from the cap ex  standpoint,  where would you max out,
              assuming no capital constraints?  What would be the maximum cap ex
              you think you could  spend  efficiently  or  effectively  for this

Kerley:       We are trying  very hard to reduce  our debt this year,  but right
              now what  we're  looking  at and very  hopeful of is that we'll be
              able to meet  our  debt  reduction  targets  and  have  additional
              capital.  We work  very  closely  together  to  look at  different
              projects  and,  obviously,  there are  several  of those.  Just as
              examples,  our  workover  projects,  that  are  paying  back  very
              quickly, we're increasing our capital allocated to those.

              We're looking at other areas,  too,  that make sense,  that have a
              very quick  payback while trying to balance the two. We do believe
              we need to reduce our debt.  We're well on our way of meeting  our
              targets  that we have and we hope that our  prices  will stay in a
              range that enables us to commit capital to fulfill any other needs
              that Richard has and to accomplish our debt reduction target.

Korell:       It's an interesting and good question,  but, against a backdrop of
              having started the year with a discipline in mind to pay down debt
              and to this point  that's been what we have done with surplus cash

              Sometimes  when you have rig  availability  and all that  being no
              problem you can put your foot on the  accelerator  with additional
              cash and do programs.  To fully answer a question  about  spending
              more capital this year, one would logically,  rather than just off
              the top of your head,  have to sit down and go  through  what rigs
              one could get in order to, for  example,  accelerate  things  like
              Overton drilling out of cash flow or other projects.

              We can  always  put  capital  into  land and  seismic  data  which
              generates more activity for future years, but, that's if we decide
              if it looked  like we were  going to have  additional  cash  flow,
              above and beyond  where we are,  above and beyond what we think we
              do. In other words,  and that could  happen,  possibly or it could
              not  happen,  through  performance  on  things we drill and put on
              production during the year we could accelerate some. It's a little
              bit of a hard  question  to answer,  but I'm going to let

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              Richard take a cut at what he  thinks  is  laying  in front of him
              that he might be able to do.

Lane:         I would say that if we were going to employ more  capital  that we
              could  look  to  add,  as  Harold  mentioned,  it's  somewhat  rig
              dependent,  but we could look to add a third rig to our program at
              Overton,  which  seems to be off to a good start and  deploy  some
              more capital there,  and possibly  deploy some more capital in our
              Arkoma drilling  program where we have quite a few ideas to pursue

              In South Louisiana,  we have just  operationally  and logistically
              been looking at doing eight to nine wells  there,  which is pretty
              much a full plate.  If we have some early  discoveries  there,  we
              could look to deploy some additional  capital on development wells
              in that  area.  Those  would be the areas I think we would look to
              spend more.

8.            Please follow-up on the 5,800 acres you picked  up as an offset in
              Overton.  What has been drilled to date, spacing wise?

Lane:         There are nine units, 640 acre units there. Like Overton, a few of
              the units have been  drilled  with a second well to 320. I believe
              there are a total of 12 wells on nine units, much the same kind of
              circumstances we see going forward here at Overton.

9.            This really  needs  to be  developed  on 80 acres,  isn't that the
              case?  Or is it 160s?

Lane:         Well, certainly, we think 160s will be an achievable target, given
              the  performance  of the wells  historically  and the wells  we've
              drilled and the drainage  patterns that we see for these wells. We
              should be able to get to 160 acres and, perhaps,  like you say, go
              down even further to 80s.

Korell:       We need to work our way down on that, incrementally, because we're
              doing a  different  sort of frac job on these than was done on the
              original 16 wells that were out there and it appears we're getting
              better  rates.  It appears that way in the early  production  data
              from the new wells. And then question is, how does that affect the
              radius of drainage?

              When  you're on 640s,  there's no doubt we need to get to 320s and
              probably little doubt that we need to get to 160s, but we'll learn
              that as we go  along,  also.  We'll  be able  to see  through  the
              performance  how that is changing the radius of drainage.  Because
              the old  original  wells  are not  draining  and  appear to not be
              draining a very large area at all.

10.           On the  new fracs,  is that the Bossier  type of  fracture  you're
              using up there now or-

Korell:       The  slick  water,  high-rate,  smaller profit  type of fracs that
              Anadarko has been using in the Bossier.

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11.           Regarding  Haileyville,  you mentioned two to four more wells this
              year.  How many  potential  locations does  that play  have to run
              beyond that or is that pretty much it?

Lane:         Well,  you'll recall how these trends lay out,  John.  They're the
              further you move along on them, they get more exploratory and more
              speculative.  Now we've bought  acreage along the trend that would
              support  doing  more  than two to four,  possibly  five to 10 more
              wells, given the acreage position we have, but the two to four I'm
              talking about are in the immediate vicinity of the existing wells.

12.           You said that these were anomalous flow rates. Do you think you've
              found something here, an  over-pressured  zone? In other words, do
              you have a new frac  technique and is this  repeatable  elsewhere?
              Are you  actively  leasing to expand this play?  And I  appreciate
              it's  speculative,  don't  misunderstand  me,  but I'm  trying  to
              understand, is this just typical Atokan and you found a good spot,
              or do you think you know something and you want to expand it? Help

Lane:         I think we know how to  explore  for these  sands.  We do a lot of
              that and we're doing a good job of it.  From a reservoir  pressure
              standpoint,  I don't think there's  anything  anomalous  there.  I
              think we have found a sweet spot,  if you will,  where these sands
              are better developed,  better processes and permeability and we're
              seeing the  results of that in the flow  rates  and,  yes,  we are
              aggressively  trying to carry what we've  learned  here and pursue
              other acreage.

Korell:       When we make the comment or someone  makes the  comment  these are
              not  typical of the Arkoma,  I guess these are not average  wells.
              But it is  typical  that  every  now and then in this  part of the
              Arkoma Basin,  particularly  on the Oklahoma  side, you will drill
              into areas that have  thicker  pay and you will have just a better
              reservoir there and more reserves, and it looks like we've hit one
              of these sweet spots as we've  chased a  particular  sand  channel
              along trend.

              Statistically  they come along,  probably  every so often,  and we
              have just hit a nice area in this one sand  channel.  It's hard to
              speculate  about whether or not the  thickness and quality  extend
              further or don't extend further and I wouldn't want anyone to plan
              we've got 10 wells that you can do these kind of multiples on.

              But we just have to drill  our way  along  into it and it's a just
              good thing that's happened to us right now.

13.           So it's a case  of rather be  lucky than smart.   Although  you're
              smart by  drilling them,  but you don't  expect to be  able to see
              anything like this in seismic and maybe identify better areas?

Korell:       No, you won't see it on seismic because of the sand thickness, but
              you have to follow the sand  trends and  recognize  that you could
              get into one of these and it's no  different

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              than what we've been telling people we're doing in the Arkoma, and
              we've just  found one  of the  nice areas  there and  it's working

14.           My memories  of the  second  well on North  Groesbec is  simply an
              acceleration  well,  it's not going to add new reserves.   Is that

Korell:       Well,  it's really two  things.  One is that it will test the same
              interval that we're  currently  producing  from,  but it will also
              have an  opportunity to test a shallower sand on the right side of
              the  fault  where  it could be  productive.  So we could  see some
              reserve adds there.

15.           Just quickly  stepping  through  the areas in  Arkoma.  You talked
              about 10 to 15 workover  potential in the second quarter,  average
              rates on those 1 to 2 million a day.  Is that a fair assumption?

Lane:         Well the examples I gave were re-frac workovers.  Those tend to be
              where we get the most  bang  for our  buck  and  achieve  the most
              increased  rate.  The  10 to  15  refers  to a  whole  variety  of
              workovers where we're cleaning out wellbores, changing out tubing,
              reperforating and those kinds of things.

16.           You're  going to get a lot lower  rate.  So how do those 10 to 15,
              how many wells  do you think we'll be  re-fracing?  Are  there any
              more of those bigger potential workovers?

Lane:         Yes.   I  think  we  have  three  to  five  that  are  re-fractype
              candidates planned for the second quarter.

17.           In the  Overton area,  people  have asked a lot of questions.  You
              talked about a partner for accelerating  development of the field.
              Is that just purely for access to capital or what's driving that?

Korell:       Well,  two  things,  and it goes back to when we started the year,
              looking at our capital program and we would like to accelerate the
              drilling  there.  We 'd like to drill more wells there than we had
              originally  in our  plan . We've  had  various  people  come to us
              wanting to get  involved in that project and we've been working on
              an arrangement that would bring in some capital that would improve
              the results for us, in other words, improve our rate of return and
              our  PVI,  which  is the  thing  that we have  our  focus  on,  on

              And  Richard  mentioned  that  we are  working  on that  and  it's
              something  that is out there.  We're not ready to, we haven't  got
              the deal done, but it would be to enhance our return.

18.           On the balance  sheet,  just looking at the $20 million of FAS-133
              charges, any of those actually  out-of-pocket cash expenditures in
              the quarter? Or is it all just balance sheet items?

Southwestern Energy Company           2001 First Quarter Results Conference Call
                                       -10-                          www.swn.com

Kerley:       Those are really just  balance  sheet  items.  I mean  nothing ran
              through  the  quarter  related  to FAS-33  in the  first  quarter.
              There's about-- and you're correct,  there's about $20 million all
              together,  about $17 million  related to the current the future 12
              months and then about $3 million that relates to 2002.

19.           Regarding the hedging program, I understood the comment, there had
              been no changes  since the last update.  I was curious with regard
              to '02 as to what you were  looking at from an  implementation  of
              strategy, either price movements up or down to ratchet that up and
              will you continue to make use of the collars? Is that how we would
              expect to see the next hedges appear?

Kerley:       We are looking at '02 quite a bit.  We,  right now,  have a pretty
              small  portion of our  production  that we would  forecast for '02
              that we've got a collar around. About 1-1/2 Bcf a quarter or 6 Bcf
              for all of next year is  collared at a collar that is $4 to $4.72.
              Current '02 prices, I think, are just a little shy of $4.70, about
              $4.68 and we are looking at that very  heavily and would expect to
              see us sometime,  probably during this summer period,  to increase
              our hedge  position in '02,  maybe  toward more,  at least,  to 50
              percent of our volume and we would be looking at whatever the best
              collar we could get at the time and try to keep it protected  that

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


Thank you.  Ladies and  gentlemen,  that does conclude the  conference  call for
today. We thank you for your  participation  and ask that you please  disconnect
your lines.

Southwestern Energy Company           2001 First Quarter Results Conference Call
                                       -11-                          www.swn.com

                          Southwestern Energy Company
                          P.O. Box 1408
                          Fayetteville, AR 72702-1408

May 2, 2001

Securities and Exchange Commission
ATTN: Filing Desk, Stop 1-4
450 Fifth Street, N.W.
Washington, DC  20549-1004


Pursuant to  regulations  of the Securities and  Exchange  Commission, submitted
herewith for filing  on behalf of  Southwestern Energy Company is Form 8-K dated
May 1, 2001.

This filing is being  effected by direct  transmission to the Commission's EDGAR

Very truly yours,

Stan Wilson