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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 25,
2011 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 25,
2011 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 Year-End 2010 Earnings
Teleconference Speakers:
Steve
Mueller; President and Chief Executive Officer Greg
Kerley; Executive Vice President and Chief Financial Officer Steve
Mueller; President and Chief Executive Officer Good morning, and thank
you for joining us. With me today are Greg Kerley, our CFO, and Brad Sylvester,
our VP of Investor Relations. If you have not
received a copy of yesterdays press release regarding our fourth quarter and
year-end 2010 results, you can find a copy on our website at www.swn.com.
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 the 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. To begin, 2010 was a
record year for Southwestern Energy. Despite lower realized gas prices, we
set new records in 2010 for production, reserves, earnings and cash flow. We
posted production growth of 35% fueled by our Fayetteville Shale play, where our
production grew 44% to 350 Bcf. We also produced 34 Bcfe from East Texas,
19 Bcf from the Arkoma Basin and 1 Bcf from the Marcellus Shale which we kicked
off late in the year. Our year-end proved
reserves also increased by 35% to a record 4.9 Tcfe. Approximately 100% of
our reserves were natural gas and 45% were classified as proved undeveloped,
down from 46% in 2009. We again recorded net positive reserve revisions
during the year, primarily due to the improving performance from our
Fayetteville Shale wells and positive price revisions due to higher average gas
prices. We replaced 430% of our
2010 production at a finding and development cost of $1.02 per Mcfe, including
revisions. Our cost structure is the key in the current gas price
environment, as our finding and development costs and production costs are among
the lowest in our industry. Fayetteville
Shale Play Now, to talk a bit
about our operating areas. The Fayetteville Shale continues to deliver
exceptional results. Our 2010 drilling program in the Fayetteville added
1.6 Tcf of new reserves at a finding and development cost of $0.86 per Mcf.
This includes net upward reserve revisions of approximately 273 Bcf, due
to improved well performance and positive revisions due to higher average gas
prices. Our finding and development cost in the Fayetteville excluding
these revisions was $1.04 per Mcf. Total proved net gas
reserves booked in the Fayetteville Shale play at year-end 2010 were 4.3 Tcf, up
39% from reserves booked at the end of 2009. The average gross proved
reserves for the undeveloped wells included in our year-end 2010 reserves was
approximately 2.4 Bcf per well, up from 2.2 Bcf per well at year-end of 2009,
and based upon our current drilling pace, we have approximately 3 years of
drilling inventory booked as PUDs. We spud 658 wells in
the Fayetteville Shale during 2010 and placed a record 553 operated wells on
production. We continued to improve our drilling and completion practices, as
our operated horizontal wells had an average completed well cost of $2.8 million
per well, compared to an average of $2.9 million per well in 2009. The decrease
in our drilling times and other savings and benefits from our vertical
integration have more than offset longer average lateral lengths. Our
average initial producing rates were approximately 3.4 million cubic feet per
day compared to last years 3.5 million cubic feet average rate. During 2010,
40% of our operated wells were drilled along the periphery of the field as the
first well in a section, which created a significantly different mix of wells
compared to our 2009 results. As for an update on our
spacing tests, at year-end 2010 we had drilled nearly all of our well spacing
tests and over 80% of these wells are currently on production. We expect to have
additional production data by the end of the first quarter of 2011 on the
remaining 40% of our acreage where more results were needed. In addition, we are
in the process of performing interference testing on certain of our
closer-spaced areas. Appalachia Switching to
Pennsylvania, we invested approximately $118 million in Pennsylvania during 2010
and participated in 21 wells, of which 6 were successful and 15 were in progress
at year-end. These 6 wells are all operated horizontal Marcellus Shale wells
located in our Greenzweig area in Bradford County that production tested between
4 and 8 MMcf per day. We placed 3 additional operated horizontal wells on
production on February 18, all of which were located in the Greenzweig area.
Total daily gross operated production from the area is currently approximately
45 MMcf per day without compression, with flowing tubing pressures ranging from
1,100 to 1,300 psi and choke sizes ranging from 23/64 to 40/64. The wells we
are currently completing have average lateral lengths of approximately 4,500
feet and are averaging 7 to 10 frac stages. We anticipate our
Marcellus activity to grow substantially in 2011 with 1.5 rigs running in 2011
compared to only 1 rig running for 10 months last year. We plan to invest
approximately $265 million in Appalachia, which includes participating in a
total of 40 to 45 wells, all of which will be operated. East Texas
Field In our East Texas
operating areas, we invested approximately $150 million and participated in 25
wells, of which 17 were successful and 8 were in progress at year-end. In June
of 2010, we sold certain oil and natural gas leases, wells and gathering
equipment in East Texas for approximately $358 million which included only the
producing rights to the Haynesville and Middle Bossier Shale intervals in
approximately 20,000 net acres. We retained
approximately 10,000 net acres which we believe is prospective for the
Haynesville and Middle Bossier Shale intervals. Our first Middle Bossier test on
this acreage, the Harris B-1H well, was placed on production on February 9th
with a 14-stage frac. The well has cleaned up nicely following a
restricted flowback program and reached an initial production rate of 9 MMcf per
day at 7,900 psi on a 17/64 choke on the 11th day of the flow back. Conventional
Arkoma In our conventional
Arkoma Basin program, we invested $13 million and only participated in 9 wells.
In 2011, we will continue concentrating on the Fayetteville and Marcellus and
again reduce the amount we plan to invest here, and in East Texas. New
Ventures As for New Ventures, at
December 31, 2010, we held over 3 million net undeveloped acres in connection
with our New Ventures prospects, of which a little over 2.5 million net acres
were located in New Brunswick, Canada and the remaining approximately 490,000
net acres are located in the U.S. In March of 2010, we
announced that the Department of Natural Resources of the Province of New
Brunswick, Canada had accepted our bids for exclusive licenses to search and
conduct an exploration program in the province in order to test new hydrocarbon
basins. In 2010, we invested approximately $10 million of the required $47
million to be invested in the province over the next three years. In January of
this year, we received initial information from a geochemical survey we had
conducted during 2010. Nearly 2,000 samples were taken in more than 35
traverses. All of the traverses had signatures indicating some combination of
oil and gas source rocks. Most of our 2011 activity in New Brunswick is shooting
370 miles of regional 2-D seismic and performing more geo-chem work. In 2010, we invested a
total of approximately $145 million in our New Ventures programs and in 2011 we
plan to invest approximately $170 million in New Ventures, which includes
drilling in at least one new area. I will now turn it over
to Greg Kerley, our Chief Financial Officer, who will discuss our financial
results. Greg Kerley Executive Vice President and
Chief Financial Officer Thank you, Steve, and good morning. I am very pleased to
report that 2010 was the best year in the companys history from a financial
perspective. For
the calendar year, we reported net income of $604 million, or $1.73 per share,
up 16% from last years adjusted net income. Cash flow from operations
(before changes in operating assets and liabilities) was $1.6 billion, up 10%
compared to last year. Our earnings and cash flow both set new records for the
company, as our production growth of 35% more than offset the effect of
significantly realized lower natural gas prices. Our
annual results for our E&P segment were truly exceptional. Operating income
for our E&P segment was $829 million, compared to $750 million (excluding a
non-cash ceiling test impairment) in 2009. For the year, we grew our
production by 35% to 404.7 Bcfe and realized an average gas price of $4.64 per
Mcf, which was down from $5.30 per Mcf in 2009. We
increased our commodity hedge position over the last few months and currently
have 186 Bcf, or approximately 40%, of our 2011 projected natural gas production
hedged through fixed price swaps and collars at a weighted average floor price
of $5.30 per Mcf. Our hedge position, combined with the cash flow
generated by our Midstream business which is not dependent on gas prices,
provides protection on approximately 55% of our total expected cash flow for
2011. Our detailed hedge position is included in our Form 10-K filed this
morning. We
continue to have one of the lowest cost structures in our industry, with all-in
cash costs of approximately $1.30 per Mcf in 2010, and a 3-year average of $1.35
per Mcf. When you include our finding and development costs, our
full-cycle costs were $2.32 in 2010 and $2.42 for the 3-year average. Our
lease operating expenses per unit of production were $0.83 per Mcfe in 2010,
compared to $0.77 in 2009. The increase was primarily due to increased gathering
and compression costs and increased costs related to higher water disposal
volumes in our Fayetteville Shale play. Our
general and administrative expenses per unit of production declined to $0.30 per
Mcfe in 2010, down from $0.35 in 2009. The decrease was primarily due to
the effects of our increased production volumes which more than offset the
effects of increased compensation and other employee-related costs primarily
associated with the expansion of our operations in the Fayetteville Shale. Taxes other than income taxes were $0.11 per Mcfe in both 2010 and
2009. Our
full cost pool amortization rate also declined during 2010 to $1.34 per Mcfe,
down from $1.51 in the prior year. The decline was due to a combination of
our low finding and development costs, the ceiling test impairment recorded in
the first quarter of 2009, and the sale of natural gas and oil properties in the
second quarter of 2010, as sales proceeds were credited to the full cost pool.
Operating income from our Midstream Services segment rose 56% to
$192 million in 2010 and EBITDA for the segment was $221 million. The
increase was primarily due to increased gathering revenues related to the
Fayetteville Shale play and an increase in the margin from our gas marketing
activities. At December 31, 2010, our Midstream segment was gathering
approximately 1.8 Bcf per day through 1,569 miles of gathering lines in the
Fayetteville Shale play, compared to gathering 1.3 Bcf per day a year ago. Our
gathering system for the Fayetteville Shale play has developed into a strategic
asset that not only supports our E&P operations but enhances our overall
returns. We are currently considering various strategic alternatives for
recognizing and maximizing the value of this asset. We
strengthened our balance sheet during 2010 and our long-term debt-to-total
capitalization ratio declined to 27%, down from 30% at year-end 2009. At
December 31, 2010, we had approximately $1.1 billion in long-term debt including
$421 million borrowed on our revolving credit facility. On February 14, we
amended and restated our credit facility which was scheduled to expire in
February 2012. The maturity date was extended to February 2016 and the
borrowing capacity was increased to $1.5 billion up from $1.0 billion with an
accordion feature that permits us to increase the facility to $2.0 billion with
agreement of existing or new lenders. We believe our credit facility will
provide us with a significant source of liquidity for the next several years.
It is a totally unsecured facility not tied to a reserve borrowing
base. We
invested $2.1 billion during 2010, compared to $1.8 billion in 2009, and we
currently expect that our total capital investments for 2011 will be
approximately $1.9 billion. There is clearly uncertainty today regarding natural
gas prices, so our capital plans will remain flexible. In
summary, 2010 was an exceptional year for us as we posted record results, both
from an operational perspective and a financial perspective. We are uniquely
positioned to weather the current gas price environment with a strong balance
sheet, excellent liquidity and one of the industrys lowest cost structures. We
are fortunate to have the largest position in one of the most profitable plays
in the country, and we look forward to adding even greater value for our
shareholders through our positions in the Fayetteville and the Marcellus and our
new exploration plays. 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 with 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, 2010. 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, 2010 2009 (in thousands) Net income (loss) attributable to Southwestern
Energy: Net income (loss) attributable to Southwestern
Energy $ 604,118 $ (35,650) 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 $ 604,118 $ 522,655
1-08246
71-0205415
(Commission File Number)
(IRS
Employer Identification No.)
77032
(Address of principal executive offices)
(Zip
Code)
EXPLANATORY
NOTE
On February 25,
2011, 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, | ||
|
2010 |
|
2009 |
|
| ||
Diluted earnings per share: |
|
|
|
Net income (loss) per share attributable to Southwestern Energy stockholders |
$ 1.73 |
|
$ (0.10) |
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 |
$ 1.73 |
|
$ 1.52 |
|
12 Months Ended Dec. 31, | ||
|
2010 |
|
2009 |
|
(in thousands) | ||
E&P segment operating income: |
|
|
|
E&P segment operating income (loss) |
$ 829,462 |
|
$ (157,725) |
Add back: |
|
|
|
Impairment of natural gas and oil properties |
-- |
|
907,812 |
E&P segment operating income, excluding impairment of natural gas and oil properties |
$ 829,462 |
|
$ 750,087 |
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 twelve months ending December 31, 2010.
|
For the 12 Months |
|
Fayetteville |
|
Ending |
|
Shale Play |
|
December 31, 2010 |
|
2010 |
|
|
|
|
Total exploration, development and acquisition costs incurred ($ in thousands) |
$ 1,781,424 |
|
$ 1,351,535 |
Reserve extensions, discoveries and acquisitions (MMcfe) |
1,431,125 |
|
1,305,609 |
Finding & development costs, excluding revisions ($/Mcfe) |
$ 1.24 |
|
$ 1.04 |
Reserve extensions, discoveries, acquisitions and reserve revisions (MMcfe) |
1,740,717 |
|
1,578,722 |
Finding & development costs, including revisions ($/Mcfe) |
$ 1.02 |
|
$ 0.86 |
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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