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UNITED STATES SECURITIES AND EXCHANGE COMMISSION 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 26,
2010 SOUTHWESTERN ENERGY COMPANY (Exact name of registrant as specified in its
charter) Delaware (State or other jurisdiction of incorporation)
2350 N. Sam Houston Pkwy. E., Suite
125, Houston, Texas (281) 618-4700 (Registrant's telephone number, including area
code) Not Applicable (Former name or former address, if changed
since last report) Check the appropriate box below if the Form 8-K
filing is intended to simultaneously satisfy the filing obligation of the
registrant under any of the following provisions: o Written
communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant
to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) o Pre-commencement
communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR
240.14d-2(b)) o Pre-commencement
communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR
240.13e-4(c))
The information in this
Report, including the exhibit, is being furnished pursuant to Item 7.01 of Form
8-K and General Instruction B.2 thereunder. Such information shall not be
deemed "filed" for purposes of Section 18 of the Securities Exchange Act of
1934, as amended, or otherwise subject to the liabilities of that section, nor
shall it be deemed incorporated by reference in any filing under the Securities
Act of 1933, as amended. SECTION 7 -
REGULATION FD Item 7.01 Regulation FD Disclosure. Exhibits.
The following exhibit is being furnished as part of this Report. Exhibit Description
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 hereunto duly authorized.
Dated: February 26,
2010 By: /s/ GREG D. KERLEY Name: Greg D. Kerley Title: Executive Vice President
and Chief Financial
Officer EXHIBIT
INDEX Exhibit Description Southwestern Energy Fourth Quarter and Full-Year 2009 Earnings
Teleconference Speakers:
Harold
Korell; Executive Chairman Steve
Mueller; President and Chief Executive Officer Greg
Kerley; Executive Vice President and Chief Financial Officer Harold
Korell Executive Chairman Good morning, and thank you for
joining us. With me today are Steve Mueller, our Chief Executive Officer,
and Greg Kerley, our Chief Financial Officer. If you have not received a copy of
yesterdays press release regarding our fourth quarter and full-year results,
you can call (281) 618-4847 to have a copy faxed to you. Also, I would
like to point out that many of the comments during this teleconference are
forward-looking statements that involve risks and uncertainties affecting
outcomes, many of which are beyond our control, and are discussed in more detail
in the risk factors and forward-looking statements sections of our Annual and
Quarterly filings with the Securities and Exchange Commission. Although we
believe the expectations expressed are based on reasonable assumptions, they are
not guarantees of future performance and actual results or developments may
differ materially. Well, 2009 was an exceptional year
for Southwestern Energy. We saw several milestones this year, including setting
new records for production, reserves, reserve replacement and cash flow, all in
a year where we saw natural gas prices which were at a seven-year low and all
the problems we encountered with the Boardwalk Pipeline. We celebrated our
5-year anniversary in the Fayetteville Shale play this year while also reaching
a production milestone of 1 Bcf per day from the play. We drilled and completed
our 1,000th well in the Fayetteville Shale, on our way to completing many more
in the years to come. Finally, we continued to have an industry-leading low cost
structure, as our finding and development cost of $0.86 per Mcfe and lease
operating expense of $0.77 per Mcfe in 2009 are among the lowest in our
industry. This is all pretty amazing when you consider that it was just five
years ago when we set all of this in motion with the discovery of the
Fayetteville Shale play. Meantime in our other areas, things
are continuing to go well in our East Texas James Lime and Haynesville
activities and in Pennsylvania, where we have just started an active drilling
program there. I will now turn the teleconference over to Steve for more details
on our E&P and Midstream activities and then to Greg for an update on our
financial results. Then we will be available for questions afterward. Steve
Mueller President and Chief Executive Officer Good morning. As Harold stated,
we had an outstanding year in 2009 and our operational metrics are some of the
best in the industry. Our production grew by 54% to a record 300 Bcfe,
primarily as a result of the growth from our Fayetteville Shale Play where our
production grew 81% to 243 Bcf. We also produced 34.9 Bcfe from East Texas
and 22.0 Bcf from the Arkoma Basin. Our year-end proved reserves
increased by 67% to a record 3.7 Tcfe. Approximately 100% of our reserves
were natural gas and 54% were classified as proved developed, down 8% from 62%
in 2008. We are also one of the few companies that have recorded net
positive reserve revisions, as the improving performance from our Fayetteville
Shale wells more than offset negative price revisions due to low gas prices and
some performance revisions in our East Texas and Arkoma Basin programs. For the last three years, our reserve
replacement has averaged over 500% of our annual production. We replaced
592% of our 2009 production at a finding and development cost of $0.86 per Mcfe,
including revisions. Excluding revisions, we replaced 561% of our 2009
production at a finding and development cost was $0.91 per Mcfe. Fayetteville Shale
Play Now, to talk a bit about our
operating areas. The Fayetteville Shale continues to deliver exceptional
results. We invested approximately $1.3 billion in our Fayetteville Shale
drilling program during 2009, adding 1.8 Tcf of new reserves at a finding and
development cost of $0.69 per Mcf. This includes net upward reserve
revisions of approximately 238 Bcf, as our improved well performance more than
offset negative revisions due to lower gas prices. The finding and
development cost excluding these revisions was $0.80 per Mcf. Total proved net gas reserves booked
in the Fayetteville Shale play at year-end 2009 were 3.1 Tcf, more than double
the reserves booked at the end of 2008. The average gross proved reserves
for the undeveloped wells included in our year-end 2009 reserves was
approximately 2.2 Bcf per well, up from 1.9 Bcf per well at year-end of 2008,
and based upon our current drilling pace, we have approximately two years of
drilling inventory booked as PUDs. During 2009, we continued to improve
our drilling and completion practices in the Fayetteville Shale play. Our
horizontal wells had an average completed well cost of $2.9 million per well,
compared to an average of $3.0 million per well in 2008, as the decrease in our
drilling times and other savings more than offset a 13% increase in average
lateral length. Our initial producing rates improved 25% over last year,
as wells placed on production during 2009 averaged initial production rates of
approximately 3.5 MMcf per day, compared to average initial production rates of
2.8 MMcf per day in 2008. Mid-year 2009, we celebrated reaching
1 Bcf per day from the Fayetteville, as gross production from our operated wells
climbed from approximately 720 MMcf per day at the beginning of 2009 to
approximately 1.2 Bcf per day at year-end. Recently, we have had some
delays due to operational issues and the colder weather that have caused 25
fewer wells to be put on production during the last few months than originally
planned. As a result, we have added 2 additional drilling rigs to help us
catch up to our projected wellcount which we expect will happen sometime in the
third quarter. We currently are running 22 drilling rigs in the
Fayetteville Shale play area, 16 that are capable of drilling horizontal wells
and 6 smaller rigs that are used to drill the vertical section of the wells.
East Texas Field In our East Texas operating areas we
had excellent results, posting production growth of 10% to 34.9 Bcfe with
reserves of approximately 330 Bcfe at year-end. In 2009, we invested
approximately $167 million and participated in 46 wells in East Texas, of which
33 were successful and 13 were in progress at year-end, resulting in a 100%
success rate. We continued to have good success in
our James Lime carbonate play and through December 31, 2009, had participated in
a total of 77 horizontal wells. Of those, 43 were operated by us and
placed on production at an average gross initial production rate of 9.8 MMcfe
per day. We also kicked off our drilling
program targeting the Haynesville and Middle Bossier Shale intervals in Shelby
and San Augustine Counties in 2009 with very good results. After our first
horizontal well production tested at 7.2 MMcf per day in the first quarter of
2009, we have drilled four additional wells in the Haynesville Shale formation
which production tested at 13.4, 16.7, 21.0 and 18.1 MMcf per day, respectively.
Additionally, we completed our first well in the Middle Bossier formation
which production tested at 11.3 MMcf per day. We are currently completing our sixth
Haynesville well, the Red River 620 #1-H, and drilling two additional
Haynesville wells in the area, the Red River 619-2 #1H and the Owens #1H, both
of which should be completed sometime in the second quarter. In total, we
have approximately 42,300 net acres we believe are prospective for the
Haynesville and Middle Bossier Shales and our average gross working interest is
approximately 61%. In addition to the James Lime,
Haynesville and Middle Bossier targets, we have placed our first Pettet oil well
on production. The Acheron #2H well was placed on production in January
and had initial production rates of 465 barrels of oil per day plus 2.5 MMcf of
gas per day. We are currently participating in two Pettet wells which are
being completed. Conventional Arkoma In our conventional Arkoma Basin
program, we had approximately 208 Bcf of reserves at year-end 2009 and produced
22.0 Bcf, compared to 24.4 Bcf in 2008. Our production decreased during
2009 primarily due to significantly lower capital investments in the area as
compared to 2008 levels. In 2009, we invested approximately $40 million in
our conventional Arkoma drilling program and participated in 20 wells, of which
15 were successful and 3 were in progress at year-end, resulting in an 88%
success rate. Appalachia At December 31, 2009, we had
approximately 149,000 net acres in Pennsylvania prospective for the Marcellus
Shale. Our undeveloped acreage position as of December 31, 2009 had an
average remaining lease term of 5 years, an average royalty interest of 13% and
was obtained at an average cost of approximately $594 per acre. During
2009, we invested approximately $40 million in Pennsylvania, almost all of which
was for acquisition of acreage, including approximately 22,829 net acres in
Lycoming County that was purchased for approximately $8.7 million, or $382 per
acre. We are currently drilling our first
horizontal well since 2008 in Pennsylvania. The Heckman Camp #1 well is
located in Bradford County, and first gas production is expected from the area
late in the 2nd quarter of 2010. Summary In summary, we are very pleased with
our results in 2009 and our planned capital investment plan for 2010 continues
to build on that success. While we are very proud of our accomplishments
in 2009 and over the past five years, we also know that we have much more work
to do. We know that our disciplined approach to capital investing, focus
on organic growth and financial flexibility will keep us extremely
well-positioned during both the good and the challenging times. We are
looking forward to what lies ahead in 2010 and in the years to come. I will now turn it over to Greg
Kerley who will discuss our financial results. Greg
Kerley Executive Vice President and Chief Financial Officer Thank you, Steve,
and good morning. We had an exceptional year in 2009, both operationally
and financially, despite natural gas prices falling to their lowest levels in 7
years. For the calendar
year, we reported net income of $523 million, or $1.52 per share, excluding a
$558 million after-tax ceiling test impairment of our oil and gas properties
during the first quarter of 2009. Cash flow from operations (before
changes in operating assets and liabilities) was up 23% to $1.4 billion as our
production growth more than offset the effect of significantly lower natural gas
prices. For the 4th
quarter, we reported earnings of $158 million, or $0.45 per share, a 51%
increase over the prior year period, as the significant growth in our production
volumes more than offset the decline in our average realized gas price.
Our production totaled 89 Bcfe in the fourth quarter, up 55% from the
prior year period, and we realized an average gas price of $5.29 per Mcf down
from $5.93 in 2008. Our commodity hedge position increased our average
realized gas price by approximately $1.50 per Mcf in the 4th quarter. We currently have
66 Bcf, or approximately 16%, of our 2010 projected natural gas production
hedged through fixed price swaps and collars at a weighted average floor price
of $8.02 per Mcf. Our detailed hedge position is included in our Form 10-K
filed yesterday. Operating income
for our E&P segment (excluding the non-cash ceiling test impairment) was
$750 million in 2009, compared to $814 million in 2008. For the year, we
grew our production by 54% to 300 Bcfe and realized an average gas price of
$5.30 per Mcf, which was down approximately 30% from the prior year. We continue to
have one of the lowest cost structures in our industry, with a full-cycle cash
cost of approximately $2.14 per Mcf in 2009, and a 3-year average of $2.75 per
Mcf. This includes our F&D costs, lease operating costs, taxes,
G&A and interest expense. As Steve noted,
our finding and development cost was $0.86 per Mcf in 2009, including revisions,
down from $1.53 in 2008. Our lease
operating expenses per unit of production were $0.77 per Mcfe in 2009, down from
$0.89 in 2008. The decrease in our operating costs was primarily due to
the impact that lower natural gas prices had on the cost of compressor fuel
during 2009. Our general and
administrative expenses per unit of production declined to $0.35 per Mcfe in
2009, down from $0.41 in 2008. The decrease was primarily due to the
effects of our increased production volumes which more than offset the effects
of increased payroll, incentive compensation and other employee-related costs
primarily associated with the expansion of our operations in the Fayetteville
Shale play. We added a total of 335 new employees during 2009. Taxes other than
income taxes were $0.11 per Mcfe in 2009, down from $0.13 in the prior year, due
to lower commodity prices and the change in the mix of our production volumes.
Our full cost pool
amortization rate also declined, dropping to $1.51 per Mcfe in 2009, from $1.99
in the prior year. The decline was due to a combination of the ceiling
test impairment recorded in the first quarter of 2009, our lower finding and
development costs and the sale of natural gas and oil properties in 2008. Operating income
from our Midstream Services segment doubled in 2009 to $123 million. The
increase was primarily due to increased gathering revenues related to production
growth in the Fayetteville Shale play, partially offset by increased operating
costs and expenses. At December 31, 2009, our Midstream segment was
gathering approximately 1.3 billion cubic feet of natural gas per day through
1,137 miles of gathering lines in the Fayetteville Shale play, compared to
gathering 802 million cubic feet per day a year ago. We invested $1.8
billion during 2009, approximately equal to our investments in 2008. We
expect that our total capital investments for 2010 will be approximately $2.1
billion. There is clearly uncertainty today regarding natural gas prices,
so our capital plans will remain flexible. If we see a repeat of the low
gas prices we saw in 2009, we will actively manage our capital program and make
reductions in our 2010 plans. However, if gas prices rebound during the
year, we could increase our planned investments and accelerate the development
of our Fayetteville Shale play by adding additional drilling rigs. We have a strong
balance sheet with significant liquidity and financial flexibility. At
year-end, we had $325 million borrowed on our $1 billion revolving credit
facility at an average interest rate of 1.1%, and had total debt outstanding of
a little less than $1 billion. This leaves us with a debt to book capital
ratio of 30% and a debt to market capitalization ratio of only 6%. That concludes my
comments, so now well turn back to the operator who will explain the procedure
for asking questions. Explanation and Reconciliation of Non-GAAP Financial
Measures We report our financial results in
accordance with accounting principles generally accepted in the United States of
America (GAAP). However, management believes certain non-GAAP performance
measures may provide users of this financial information additional meaningful
comparisons between current results and the results of our peers and of prior
periods. One such non-GAAP financial measure
is net cash provided by operating activities before changes in operating assets
and liabilities. Management presents this measure because (i) it is accepted as
an indicator of an oil and gas exploration and production companys ability to
internally fund exploration and development activities and to service or incur
additional debt, (ii) changes in operating assets and liabilities relate to the
timing of cash receipts and disbursements which the company may not control and
(iii) changes in operating assets and liabilities may not relate to the period
in which the operating activities occurred. Additional non-GAAP financial
measures we may present from time to time are net income attributable to
Southwestern Energy, diluted earnings per share attributable to Southwestern
Energy stockholders and our E&P segment operating income, all which exclude
certain charges or amounts. Management presents these measures because (i)
they are consistent with the manner in which the Companys performance is
measured relative to the performance of its peers, (ii) these measures are more
comparable to earnings estimates provided by securities analysts, and (iii)
charges or amounts excluded cannot be reasonably estimated and guidance provided
by the Company excludes information regarding these types of items. These
adjusted amounts are not a measure of financial performance under GAAP.
See the reconciliations below of
GAAP financial measures to non-GAAP financial measures for the twelve
months ended December 31, 2009 and December 31, 2008. Non-GAAP financial
measures should not be considered in isolation or as a substitute for the
Company's reported results prepared in accordance with GAAP.
12 Months Ended
Dec. 31, 2009 2008 (in
thousands) Net
income (loss) attributable to Southwestern Energy: Net
income (loss) attributable to Southwestern Energy $
(35,650) $
567,946 Add
back: Impairment
of natural gas and oil properties (net of taxes) 558,305 -- Net
income attributable to Southwestern Energy, excluding
impairment of natural gas and oil properties $
522,655 $
567,946
1-08246
71-0205415
(Commission File Number)
(IRS
Employer Identification No.)
77032
(Address of principal executive offices)
(Zip
Code)
EXPLANATORY
NOTE
On February 26,
2010, at 10:00am Eastern, Southwestern Energy Company will host a
telephone conference call for investors and analysts. The prepared
teleconference comments are furnished herewith as Exhibit 99.1.
Number
SOUTHWESTERN ENERGY COMPANY
Number
|
12 Months Ended Dec. 31, | ||
|
2009 |
|
2008 |
|
| ||
Diluted earnings per share: |
|
|
|
Net income (loss) per share attributable to Southwestern Energy stockholders |
$ (0.10) |
|
$ 1.64 |
Add back: |
|
|
|
Impairment of natural gas and oil properties (net of taxes) |
1.62 |
|
-- |
Net income per share attributable to Southwestern Energy stockholders, excluding impairment of natural gas and oil properties |
$ 1.52 |
|
$ 1.64 |
|
12 Months Ended Dec. 31, | ||
|
2009 |
|
2008 |
|
(in thousands) | ||
E&P segment operating income: |
|
|
|
E&P segment operating income (loss) |
$ (157,725) |
|
$ 813,504 |
Add back: |
|
|
|
Impairment of natural gas and oil properties |
907,812 |
|
-- |
E&P segment operating income, excluding impairment of natural gas and oil properties |
$ 750,087 |
|
$ 813,504 |
Finding and development costs - Finding and development (F&D) costs are computed by dividing acquisition, exploration and development capital costs incurred for the indicated period by reserve additions, including reserves acquired, for that same period. The following computes F&D costs using information required by GAAP for the periods ending December 31, 2009 and December 31, 2008, and three years ending December 31, 2009.
|
For the 12 Months Ending December 31, 2009 |
|
For the 12 Months Ending December 31, 2008 |
|
For the 3 Years Ending December 31, 2009 |
|
Fayetteville Shale Play 2009 |
|
Fayetteville Shale Play 2008 |
|
|
|
|
|
|
|
|
|
|
Total exploration, development and acquisition costs incurred ($ in thousands) |
$ 1,529,876 |
|
$ 1,559,995 |
|
$ 4,460,747 |
|
$ 1,259,151 |
|
$ 1,191,558 |
Reserve extensions, discoveries and acquisitions (MMcfe) |
1,685,191 |
|
920,181 |
|
3,113,227 |
|
1,576,980 |
|
824,706 |
Finding & development costs, excluding revisions ($/Mcfe) |
$ 0.91 |
|
$ 1.70 |
|
$ 1.43 |
|
$ 0.80 |
|
$ 1.44 |
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe) |
1,778,045 |
|
1,018,281 |
|
3,335,156 |
|
1,814,665 |
|
983,635 |
Finding & development costs, including revisions ($/Mcfe) |
$ 0.86 |
|
$ 1.53 |
|
$ 1.34 |
|
$ 0.69 |
|
$ 1.21 |
The company believes that providing a measure of F&D costs is useful for investors as a means of evaluating a companys cost to add proved reserves, on a per thousand cubic feet of natural gas equivalent basis. These measures are provided in addition to, and not as an alternative for, and should be read in conjunction with, the information contained in Southwesterns financial statements prepared in accordance with GAAP (including the notes thereto). Due to various factors, including timing differences and the SECs 2009 adoption of a number of revisions to its oil and gas reporting disclosure requirements, F&D costs do not necessarily reflect precisely the costs associated with particular reserves. For example, exploration costs may be recorded in periods prior to the periods in which related increases in reserves are recorded and development costs, including future development costs for proved undeveloped reserve additions, may be recorded in periods subsequent to the periods in which related increases in reserves are recorded. In addition, changes in commodity prices can affect the magnitude of recorded increases in reserves independent of the related costs of such increases. As a result of the foregoing factors and various factors that could materially affect the timing and amounts of future increases in reserves and the timing and amounts of future costs, including factors disclosed in Southwesterns filings with the SEC, future F&D costs may differ materially from those set forth above. Further, the methods used by Southwestern to calculate its F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwesterns F&D costs may not be comparable to similar measures provided by other companies.
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