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) February 15, 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)



Item 7.(c)

Exhibits                                                              Reference

        (99.1)   Conference Call Summary dated February 15, 2002.     p. 3 - 10

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:  February 19, 2002                       BY:   /s/ GREG D. KERLEY
     ---------------------                     ---------------------------
                                                     Greg D. Kerley
                                                 Executive Vice President
                                               and Chief Financial Officer

                                      - 2 -

Southwestern Energy Company                              Conference Call Summary

              2001 Fourth Quarter, Year-End Results Conference Call
                            Friday, February 15, 2002

                                   Chaired by
                                  Harold Korell
                      President and Chief Executive Officer

     Good morning and thank you for joining us today.  With me are Richard Lane,
our Executive Vice President of our Exploration and Production  company and Greg
Kerley, our Chief Financial Officer. After some preliminary comments,  I'll turn
the floor over to  Richard  for an update on our  operations  in E&P 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
year-end results,  you can call Carol 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  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.

First of all,  I'm happy and  proud to report on the  successful  year we had in
2001. Our outstanding drilling results generated double-digit  production growth
and 224% reserve  replacement at a finding cost for the capital  invested during
the year of $1.11 per Mcfe.  Financially,  we had a tremendous year as well, and
posted the highest level of earnings and cash flow in the Company's history.

These are great results,  but the real driver behind our performance in 2001 and
for the last three years, for that matter, is having the right team of people in
place and creating an  environment  that fosters the  generation  of ideas.  Our
overall Company strategy  emphasizes the balance of risk in our capital program.
The combination of the  dependability of the cash flow and earnings from the gas
distribution business and our low-risk drilling projects in the Arkoma Basin and
East Texas allow us to take a swing at the fence in South Louisiana  exploration
projects.  We like the mix of this  activity  and will  continue  to exploit our
competitive advantage in these strategy areas.

I believe  that our  performance  is  starting to stand out and  investors  have
started to look at us as a Company  that is  different  from the pack due to our
focus on present value added per dollar  invested.  Although we're entering 2002
with uncertain  product prices, we have the ability to flex our capital program.
We will continue to build on the base that we've established over the past three
years. Now I'd like to turn the teleconference  over to Richard for an update on
the E&P operations.

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     Thank you,  Harold.  2001 was a very  successful year for the Company's E&P
segment. We were able to replace 224% of our production with over 89 Bcfe of new
reserve  additions,  derived  almost  entirely  through  our  drilling  program.
Production  for the full year was 39.8 Bcfe,  an 11% increase over the 35.7 Bcfe
produced in the year 2000.  Production was 10.5 Bcfe for the fourth quarter,  up
from 9.1 Bcfe for that same period in 2000.  In total,  we  participated  in 101
wells in 2001,  of which 80 were  successful.  We maintained  our  risk-balanced
drilling  approach in 2001 by continuing to focus in our core areas:  the Arkoma
Basin;   Permian  Basin;  South  Louisiana;   and  East  Texas.  We  achieved  a
Company-wide  finding  and  development  cost of $1.11  per Mcfe,  exclusive  of

In the Arkoma Basin,  we had an 81% success rate with 42 producers out of the 52
wells drilled.  We achieved strong drilling  results in both the Fairway area in
Arkansas,  as well as on the Oklahoma  side of the basin.  For one project,  our
Haileyville area delivered  particularly  outstanding  results,  with six of ten
wells  completed and net  production  rates  reaching a high of 15 million cubic
feet per day in July. Additionally in the Arkoma Basin, our workover program for
2001 grew into a significant  part of our  strategy.  We completed 55 workovers,
which added 4.4 million cubic feet a day of net production at a net cost of $1.4
million.  In 2001,  we also built an  inventory of projects that we have already
begun to develop in 2002.

In the Permian Basin, we drilled 26 wells and completed 19 of them,  including a
discovery at our Cowden Ranch,  where we have additional  development  plans for
this year. We continue to pursue our joint venture  acreage in the basin,  which
provides us low cost access  to exploration  lands.  Although  we have grown our
proven reserve base significantly in the Permian Basin over the last four years,
our finding costs have increased. In light of the decreased capital plan we have
for 2002, we will be reducing our investing in this area.

At our Overton Field, in Smith County,  Texas, we had 15 successful wells out of
15 drilled in 2001. As a result of our drilling  program,  we have increased the
field's  gross  production to  approximately  16 million cubic feet per day. Our
engineering and drilling efficiencies in the field have allowed us to reduce the
days  required to drill and complete an Overton well to  approximately  30 days,
and this represents a 25% reduction in drilling time.

Moving to South  Louisiana,  we  continued  to achieve  significant  exploration
success.  In 2001,  we had three  discoveries  at our  Malone,  Horeb and Crowne
prospects. These discoveries bring our total successful well count to six out of
the  last  nine  exploratory  wells  drilled,  and  eight  out  of the  last  11
exploration and development wells overall.  We recently reached TD and completed
the Norman Breaux #1 well,  which is the  development  well on our North Grosbec
discovery.  After overcoming  significant  mechanical problems and cost overruns
during the drilling of this well,  the Norman Breaux was online and producing at
approximately  20 million cubic feet per day and 800 barrels of condensate.  Our
discovery  well,  the Brownell  Kidd #1,  continues to be a high  deliverability
well,  currently  producing 16 million cubic feet per day and 580 barrels of oil
per day.

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At our last teleconference in late October, we had just spud our Crowne prospect
in Cameron Parish.  We announced in December that the Miami  Corporation  #27-1,
which  is the  test  well for the  prospect,  encountered  75 feet of pay in the
targeted Planulina  objective section.  We anticipate first production within 30
days for this well. Also on the Crowne prospect,  a development  well, the Miami
Corporation  #34-2  has been  spud  and  should  reach  total  depth  in  March.
Southwestern  operates the Crowne project and we have a 40% working  interest in
both of these wells.

Additionally,  at our  last  teleconference,  I  discussed  that  we had  made a
discovery  at our Horeb  prospect  in Acadia  Parish.  Since that time,  we have
placed the Mire #1 well on production and it is currently producing 12.6 million
cubic feet per day and 159  barrels of oil per day.  We  operate  this well,  as
well, and have a 21.5% working interest.

In summary, we are very pleased with the results of our 2001 program. Across the
board,  we  achieved  strong  operating   results  with  excellent  finding  and
development costs, high reserve  replacement  ratios and significant  production
increases  through  drilling.  Additionally,  although  we started the year with
higher lifting costs per unit of production,  we've made progress  driving those
costs down during the year.  Our strategy of risk  balanced  drilling is working
and allowing us to create value. I'll now turn the  teleconference  over to Greg
Kerley, who will discuss the Company's financials.

     Thank you, Richard,  and good morning.  In 2001, we set new records for net
income and cash flow.  For the year,  we reported net income of $35.3 million or
$1.38 per  share,  up over 70% from the $20.5  million  or 82 cents per share we
reported in 2000,  before  unusual items.  Cash flow from  operating  activities
before  changes in working  capital rose 37% to $112.7  million  during 2001, up
from $82.4  million  in 2000,  excluding  unusual  items.  Growth in  production
volumes and higher gas prices led to the record financial results.

For the fourth  quarter of 2001,  we reported net income of $7.4 million or $.29
per share,  compared to $9.1  million or $.36 per share for the same period last
year.  Cash flow from  operating  activities was $26.3 million during the fourth
quarter,  slightly lower than the $27.7 million from the fourth quarter of 2000.
Lower operating income from the Company's utility system due to warm weather and
higher  depreciation  and  depletion  expense led to the drop in earnings in the
fourth quarter.  Operating income in 2001 from our E&P segment  increased 70% to
$69.3 million,  due to the record production levels that Richard discussed,  and
higher realized gas prices.

In 2001 we realized an average gas price of $3.85 per Mcf,  including the affect
of our hedges,  up from $2.88 in 2000.  To limit the impact of declining oil and
gas prices on our cash flow,  we've hedged about 50 percent of our expected 2002
oil and gas  production.  The Company  has 19 Bcf hedged in 2002,  at a weighted
average NYMEX price of $3.23 per Mcf, and  approximately  280,000 barrels of oil
hedged at about $20 a barrel.

Our production and operating  expenses for the E&P segment,  while still some of
the lowest in the  industry,  rose during 2001 due to increases in service costs
and the increased level of
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workovers that Richard  discussed that we  made to  take advantage of the higher
commodity  prices.  Lifting costs on an equivalent unit of production basis were
45  cents  per Mcf in  2001,  compared  to 40  cents  last  year.  Depreciation,
depletion and  amortization  expense for the E&P segment was also up in 2001 due
to higher production  volumes and a higher  amortization  rate. The amortization
rate for the full cost pool in 2001  averaged  $1.14 per Mcf, as compared to the
prior year rate of $1.06.

Operating  income for our gas  distribution  segment was $10.3  million in 2001,
down from $12.6  million in 2000,  excluding  income from our  Missouri  utility
properties  that  were  sold in May of  2000.  The  lower  results  were  due to
significantly  warmer weather  experienced during the fourth quarter of 2001 and
increased bad debt expense  caused by higher  natural gas prices.  Finally,  our
energy  marketing  efforts  provided about $2.7 million of additional  operating
income in 2001, compared to $2.5 million in 2000.

Our strong financial results also allowed us to reduce our long-term debt by $46
million during the year. Our debt continues to carry a favorable  interest rate,
which  currently  averages  about 5.8%. At year-end,  our capital  structure was
about 66% debt-to-total  capital, down from 74% debt-to-total capital at the end
of 2000. Our capital  investments  totaled  $106  million during  2001, with our
E&P segment  accounting  for $99 million of that amount.  Our minority  interest
partner in  Overton  funded  $13.5  million of our  Exploration  and  Production
expenditures in 2001.

As we announced  in our press  release  yesterday,  we are revising our guidance
regarding our capital  investment  program and production outlook for 2002. As a
result  of  current  lower  natural  gas  prices,  we  reduced  our E&P  capital
investment program by $9 million, bringing the total planned capital investments
in Exploration and Production  down to $61 million,  compared to the $70 million
previously announced on December 21st. As a result of the reduced  expenditures,
we are lowering our  production  target in 2002 to a range of 41.5 to 42.5 Bcfe,
down from our previous  guidance of 43 to 44 Bcfe.  That  concludes my comments.
We'll turn back to the  operator,  who will  explain  the  procedure  for asking

                              Questions and Answers

1.       Would  you give me the  split of  reserves  in East  Texas and then the
         Permian Basin?

Lane:    At year-end, of the 402 Bcf that we have as a Company, Overton is about
         55 to 60 Bcf of that total;  the Arkoma is about 186 Bcf of that total;
         and the Permian is about 60 Bcf of that total.

2.       How much was booked at Overton when you purchased it?

Korell:  7.5 Bcfe in 2000.

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3.       I  know  you've  already  hedged  9.2  Bcf of gas  in  2003.  Have  you
         subsequently hedged any more in 2003?

Kerley:  No, we haven't.  The only changes that we've had to our hedge  position
         we discussed in our press  release.  We did put the 280,000  barrels of
         oil hedge in place for 2002. We haven't changed any position in 2003 at
         all, so we still have the same position there.

4.       Your decreased budget for 2002, if I read the press release  correctly,
         is  targeting  Arkoma and East Texas where the decline will be. Why are
         you targeting those two areas for the decline?

Lane:    We're  looking at a number of variables  when we try to re-shape  that.
         What we have to look at is where do we have lost  opportunity and where
         do we control the  projects,  that if we don't do them,  they're  still
         there for us at  another  day.  We try to shape that all up and get the
         best program out of it. We have about $4 million lower than  previously
         talked about for the Arkoma.  We participate  in a lot of  non-operated
         wells  and we think  that  will be off a  little.  So  there  will be a
         natural decline in that part of our investing there. At Overton,  about
         $5 million less than we previously talked about. Again, that's an asset
         that we  control.  We don't have to do those and we can still  maintain
         our position out there.

5.       So a lot of it has to do with lease  requirements  and just whether you
         control it or not?

Lane:    Yes. That's one significant part of it.

6.       Are you planning a partnership similar to the one you had over the past
         year or so in Overton for 2002 and 2003?

Lane:    We  haven't  looked  at  anything  out  into  2003.  We have  had  some
         discussions  for this year and we're not  certain  where that will turn
         out right now.

7.       G&A seemed to go up some in the fourth quarter. Can you give some color
         on that? I know it's choppy, quarter to quarter.

Kerley:  Yes, it typically is. It was up about $.5 million dollars in the fourth
         quarter.  I would say that a good part of that  probably  is related to
         some of the balance of  write-offs  in the utility and their  increased
         expenses for the year. Things that are choppy year-to-year.  So there's
         nothing significant there.

8.       Many companies are reporting very high finding costs,  so your $1.11 is
         indeed impressive in comparison.  Hopefully,  you can give us some sort
         of  range  of  estimates  of  finding  costs  in the  various  regions,
         particularly in South Louisiana.  As you know, Gulf Coast drilling, and
         offshore drilling is much more expensive, and that's where we're seeing
         the costs rise pretty  dramatically.  Your great  spate of success,  it
         looks  like,  is in South  Louisiana.  Can you give us  guidance of the
         finding  costs  there,  and how you're  able to  achieve  the string of

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Lane:    If you look at three-year numbers,  which might be more meaningful,  in
         the  Arkoma  Basin,  we've  achieved  about a $1.05  per Mcfe over that
         period.  In the Permian  Basin,  about $1.33 per Mcfe and in Louisiana,
         $1.65 per Mcfe, all costs considered.  That's a three-year  breakout of

9.       Looking forward to your exploration slate in Louisiana, could you focus
         or  articulate  where you think the key projects are, that we should be
         watching the reserve potential in those areas?

Lane:    The Gulf Coast remains our highest  potential  area, in particular,  in
         Louisiana.  We plan to drill  five to six wells in that area this year.
         One development  well, and the rest plan to be exploratory  wells.  The
         Crowne well I mentioned  that is  currently  drilling,  is an important
         well for us to  further  develop  that  discovery.  A  series  of other
         exploration wells in South Louisiana will take us through the year.

10.      We'd like to gain a sense of future  inventory  for East Texas.  I know
         there's some down-spacing  issues there.  Could you bring us up to date
         on the down  spacing  and what type of  potential  locations  you would
         receive because of that?

Lane:    Sure, on finding costs, I would just add that we didn't discuss Overton
         because we were talking about three-year numbers.  But if you look at a
         one-year number, we're down around $.80 per Mcfe for that property. So,
         that helps  significantly  there. In terms of the future development of
         the field  would be the  ability to drill the field  down to  certainly
         160-acre  spacing.  All  of our  data  says  that  80-acre  spacing  is
         achievable  also.  But on  160-acre  spacing  basis,  which we have the
         regulatory  issues  filed  to be able to do  that  efficiently,  we see
         approximately  another  30  wells  just to get  down  to that  160-acre

11.      Isn't  there some sort of south  acreage  that  you've  farmed  into at

Lane:    Yes, there's about six thousand acres south of Overton Field, I believe
         it's 5,800 acres that we call our MAP acreage or South Overton area. We
         have additional development potential down there, as well.

12.      If I look at your  revised  capital,  just under $70 million and if you
         look at very low gas prices -- you'll get cash flow above that.  Is the
         thought  to try to reduce  that by a  certain  dollar  amount?  Is that
         what's  driving  Cap Ex coming  down  despite  your cash flow  being in
         excess of $70 or $80 million on $2.25 - $2.50 gas?

Korell:  The capital  program  that we've  planned  right now is  conservatively
         natured. As you look at the forward strip, you see a price that's maybe
         more in the $2.40 to $2.50 per Mcf range.  We made the decision to plan
         our capital program around a $2.25 NYMEX price,  basically. We decided,
         at the outset here, to plan for a reduced  program with the  assumption
         that we might see lower gas prices,  but knowing that we could flex our
         program up if we want to. The flex in our

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         program  pretty much is that we can choose  when to drill Overton.  One
         might ask why be  aggressively  drilling out there while prices are low
         if those wells come on at fairly high rates in their first year.  So we
         control  that. We're  seeing  less  AFE's from  outside  parties in the
         Arkoma Basin. If we're not getting the normal  stream of AFE's from our
         partners in the Arkoma, then we won't be spending those dollars.

         Then, in South Louisiana, as you know, when you've made the investments
         in 3-D seismic,  you've traded positions,  you have lease options,  you
         have  programs  that are  ongoing.  We have an  additional  3-D project
         that's  ongoing  there.  All these  things  have time  clocks  that are
         running on them.  The  economics  are still very good if we continue to
         have the kind of  success  we've had in South  Louisiana,  or even less
         successful than we've had, would still be good.

         So we want to keep that going. It's our view that, hopefully, we'll see
         prices  strengthening  later in the year or into next year. I think the
         way we've  got this plan put  together  we'll get a  combination  of us
         coming out of the year at some pretty high producing rates,  hopefully,
         to take  advantage of higher  prices,  then take a whack at paying down
         more debt again.

13.      What I'm getting at is whether Greg has your arm twisted, and Richard's
         arm twisted in paying down a certain dollar amount,  or is it more just
         play it by ear and let's see what gas  prices do during  the  course of
         the year?

Korell:  Well,  it's the  latter and I think it is just the way we ought to play
         the game. We've got inventory we could drill, certainly. But why should
         we extend  ourselves  not knowing where prices are going to be? We need
         to be careful  that we match our  program up with our cash flow and not
         be incurring more debt.

14.      Obviously you had some downward  reserve  revisions  because of prices.
         Could you tell us what areas  those were from,  primarily?  What prices
         were used to determine  this?  And I guess it's the same as your PV-10.
         And finally,  what are the  development  costs in your  reserve  report
         required to fully develop your reserve base?

Lane:    The year-end  price that we utilized for 2001 was $2.65 per Mcf for gas
         and $19.84 per barrel for oil. We had downward revisions of about 27 to
         28  Bcfe,  mostly  attributable  to  price.  About  half of that  price
         revision  was from the Arkoma  and the rest  spread  between  our other
         areas.  In terms of future  required  development  capital that we have
         recorded, that amount is about $57 million.

15.      Can you give us any color as to whether you've had  conversations  with
         the rating  agencies?  We've had certainly an excellent year. Our total
         debt we're paying,  as Greg said,  about 5.8%.  There's  really not any
         urgency  to pay down much more debt.  But I'm  curious as to whether or
         not the rating  agencies have paid  attention to what we've done in the
         last year and where we stand.

         Kerley:  We do stay in  contact  with the  rating  agencies,  typically
         quarterly.  We also meet with them annually and present a  presentation
         and plan where we go into a lot of detail about our next

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         12 months  and where we see  things  beyond  that.  One thing  that has
         helped us  significantly  in the last several years, is we've done what
         we told the rating  agencies we were going to do. And  exactly  what we
         ended up this year  is really  well within  the  parameters  of what we
         told them our  expectations  were.  I think  they'll  be very  pleased.
         They've indicated that as we've gone along through the year.

         We haven't  had any recent  discussions  with them  except that I think
         that with some of the things that have been going on with  Enron, etc.,
         they sent out some basic surveys to all companies regarding if they had
         any triggers in their debt instruments that caused immediate payment or
         anything else. We don't have any of those.  We just  responded,  as I'm
         sure all the rest of the  inquiries  that they had,  I think  they sent
         almost three thousand  inquiries,  probably just a blanket inquiry.  We
         have, I think, good  relationships  with them. They want to know what's
         going on all the time. We try to keep them up to date.

16.      In  Harold's  opening  statements,  he  implied  the  status quo on the
         utility  side.  Certainly the utility has helped us with our cash flow.
         Can I take it to mean that the utility is not being  actively  marketed
         at this time?

Kerley:  That's  correct.  We're  still  exactly where we were  a full year ago,
         when  we  made  the  decision  to  pull  the  utility  off  the  market
         because of the hedge position that we put in place more than a year and
         a half  ago.  It put us in a  position  to get  our  capital  structure
         started back well on a road of significant improvement. There are a lot
         of benefits  that the utility  provides to us as we talked about in the
         past,  that helps us  significantly  in our debt position.  The utility
         also adds a continuing stable base of our cash flow and earnings,  that
         I think the market looks at, especially in the time that we're in right
         now -- a downturn in prices,  compared to what they've  been.  Although
         these are still pretty attractive prices historically.  It's a plus for
         us and we can plan to continue to operate it.

Kerley:  This is Greg  Kerley,  again.  Thank you for joining us and please feel
         free to call me with any questions  you may have or other  information.
         This concludes our teleconference.

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

February 19, 2002

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
February 15, 2002.

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

Very truly yours,

Stan Wilson