We file periodic reports and proxy statements with the SEC. The public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We file our reports with the SEC electronically. The SEC maintains an internet website that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address of the SEC’s website is www.sec.gov. 

ITEM 1. BUSINESS

Southwestern Energy Company is an independent energy company engaged in natural gas and oil exploration, development and production (E&P). We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses, which we refer to as Midstream Services. 

Exploration and Production - Our primary business is the exploration for and production of natural gas and oil, with our current operations being principally focused within the United States on development of an unconventional natural gas reservoir located on the Arkansas side of the Arkoma Basin, which we refer to as the Fayetteville Shale play.  We are also actively engaged in exploration and production activities in Pennsylvania, where we are targeting the unconventional natural gas reservoir known as the Marcellus Shale, and to a lesser extent in Texas and in Arkansas and Oklahoma in the Arkoma Basin.  We also actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures.”  We primarily conduct our exploration and production operations through our wholly-owned subsidiaries, SEECO, Inc., or SEECO, and Southwestern Energy Production Company, or SEPCO.  SEECO operates exclusively in Arkansas where it holds a large base of both developed and undeveloped natural gas reserves, and conducts the Fayetteville Shale drilling program and the conventional Arkoma Basin operations in the Arkoma Basin.  SEPCO conducts development drilling, exploration programs and production operations in Pennsylvania, Oklahoma, Texas, Arkansas and Louisiana.  SWN Drilling Company, Inc., formerly known as DeSoto Drilling, Inc., a wholly-owned subsidiary of SEPCO, operates drilling rigs in Arkansas, Pennsylvania and Louisiana, as well as other operating areas.  We also provide oilfield products and services through DeSoto Sand, L.L.C. and SWN Well Services, L.L.C., both of which are wholly-owned subsidiaries of SWN E&P Services, L.L.C.  Our Canadian operations are conducted by our subsidiary, SWN Resources Canada Inc. 

Midstream Services - We engage in natural gas gathering activities in Arkansas, Texas and Pennsylvania through our gathering subsidiaries, DeSoto Gathering Company, L.L.C., or DeSoto Gathering, and Angelina Gathering Company, L.L.C., or Angelina Gathering. DeSoto Gathering and Angelina Gathering primarily support our E&P operations and generate revenue from fees associated with gathering of natural gas. Our natural gas marketing subsidiary, Southwestern Energy Services Company, or SES, captures downstream opportunities which arise through the marketing and transportation of the natural gas produced in our E&P operations. 

The vast majority of our operating income and earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, is derived from our E&P business.  In 2012, 64% of our operating income and 79% of our EBITDA were generated from our E&P business, absent our $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties, compared to 77% of our operating income and 84% of our EBITDA in 2011, and 81% of our operating income and 86% of our EBITDA in 2010.  In 2012, 36% of our operating income and 21% of our EBITDA were generated from Midstream Services, absent the non-cash ceiling test impairment of our natural gas and oil properties, compared to 23% of our operating income and 16% of our EBITDA in 2011, and 19% of our operating income and 14% of our EBITDA in 2010.  EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss).  

Our Business Strategy

Since 1999, our management has been guided by our formula, which represents the essence of our corporate philosophy and how we operate our business:

Our formula, which stands for “The Right People doing the Right Things, wisely investing the cash flow from our underlying Assets will create Value+,” also guides our business strategy.  We are focused on providing long-term growth in the net asset value of our business.  In our E&P business, we prepare an economic analysis for each investment opportunity based upon the expected present value added for each dollar to be invested, which we refer to as Present Value Index, or PVI.  The PVI for each project is determined using a 10% discount rate.  We target creating at least $1.30 of pre-tax PVI for each dollar we invest in our E&P projects.  Our actual PVI results are utilized to help determine the allocation of our future capital investments. The key elements of our business strategy are: 

Recent Developments

2013 Planned Capital Investments and Production Guidance.  Our planned capital investment program for 2013 is approximately $2.0 billion, which includes approximately $1.8 billion for our E&P segment, $160 million for our Midstream Services segment and $40 million for corporate and other purposes.  Our 2013 capital program is expected to be funded primarily by our cash flow from operations and borrowings under our $1.5 billion unsecured revolving credit facility.  The planned capital program for 2013 is flexible and we will reevaluate our proposed investments as needed to take into account prevailing market conditions. Based on our capital program, we also announced our targeted 2013 natural gas and oil production of approximately 628 to 640 Bcfe, an increase of approximately 12% over our 2012 production, using midpoints.

Exploration and Production

Overview

Our operations in our E&P segment are focused primarily on the Fayetteville Shale, an unconventional reservoir located in the Arkoma Basin in Arkansas.  In addition to our Arkansas operations, we are also continuing to expand our drilling program on our acreage in Pennsylvania targeting the Marcellus Shale and we will conduct both conventional and unconventional operations targeting various formations as part of our New Ventures projects, which include unconventional horizontal oil plays targeting the Lower Smackover Brown Dense, or LSBD, formation in Arkansas and Louisiana, the Marmaton and Atoka formations in the Denver-Julesburg Basin in Colorado, the Bakken and Three Forks formations in Montana and exploration activities in New Brunswick, Canada.  We continue to actively seek to develop both conventional and unconventional natural gas and oil resource plays with significant exploration and exploitation potential.

Our E&P segment recorded an operating loss of $1,411.2 million in 2012 as a result of the recognition of a $1,939.7 million, or $1,192.4 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded for the twelve months ended December 31, 2012. Our E&P segment recorded operating income of $825.1 million in 2011 and operating income of $829.5 million in 2010.  Our operating income in 2012 decreased as the revenue impact of our 13% increase in production was more than offset by the 18% decline in our average realized gas prices, the ceiling test impairment and an increase in operating costs and expenses that resulted from our significant production growth. The slight decrease in operating income in 2011 was primarily due to lower prices realized from the sale of our natural gas production and an increase in operating costs and expenses which was largely offset by a 24% increase in our total natural gas and oil production.   EBITDA from our E&P segment was $1.3 billion in 2012, compared to $1.5 billion in 2011 and $1.4 billion in 2010. Our EBITDA decreased in 2012 as our increased production was more than offset by lower average realized gas prices and increased operating costs and expenses that resulted from our significant production growth.  The increase in our EBITDA in 2011 was due to our increased production volumes which was partially offset by lower average realized gas prices and increased operating costs and expenses.  EBITDA is a non-GAAP measure. We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a reconciliation of EBITDA to net income (loss) attributable to Southwestern Energy.

Our Proved Reserves

Our estimated proved natural gas and oil reserves were 4,018 Bcfe at year-end 2012, compared to 5,893 Bcfe at year-end 2011 and 4,937 Bcfe at year-end 2010.  The overall decrease in total estimated proved reserves in 2012 was primarily due to the low natural gas price environment.  Since our proved reserves are primarily natural gas and as such our reserve estimates and the after-tax PV-10 measure is highly dependent upon the natural gas price used in the after-tax PV-10 calculation.  The average prices utilized to value our estimated proved natural gas and oil reserves as of December 31, 2012 were $2.76 per MMBtu for natural gas and $91.21 per barrel for oil compared to $4.12 per MMBtu for natural gas and $92.71 per barrel for oil at December 31, 2011 and $4.38 per MMBtu for natural gas and $75.96 per barrel for oil at December 31, 2010.

The after-tax PV-10, or standardized measure of discounted future net cash flows relating to proved natural gas and oil reserve quantities, was $2.1 billion at year-end 2012, compared to $3.5 billion at year-end 2011 and $3.0 billion at year-end 2010.  The decrease in our after-tax PV-10 value in 2012 was primarily caused by the low natural gas price environment. The increase in our after-tax PV-10 value in 2011 over 2010 was primarily due to the increase in our reserves, partially offset by a decrease in average 2011 prices for natural gas from average 2010 prices. The difference in after-tax PV-10 and pre-tax PV-10 (a non-GAAP measure which is reconciled in the 2012 Proved Reserves by Category and Summary Operating Data table below) is the discounted value of future income taxes on the estimated cash flows.  Our year-end 2012 estimated proved reserves had a present value of estimated future net cash flows before income tax, or pre-tax PV-10, of $2.3 billion, compared to $4.8 billion at year-end 2011 and $4.3 billion at year-end 2010. 

We believe that the pre-tax PV-10 value of the estimated cash flows related to our estimated proved reserves is a useful supplemental disclosure to the after-tax PV-10 value.  While pre-tax PV-10 is based on prices, costs and discount factors that are comparable from company to company, the after-tax PV-10 is dependent on the unique tax situation of each individual company.  We understand that securities analysts use pre-tax PV-10 as one measure of the value of a company’s current proved reserves and to compare relative values among peer companies without regard to income taxes.  We refer you to Note 4 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved gas and oil reserves, to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K, and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

Approximately 100% of our year-end 2012 estimated proved reserves were natural gas and 80% were classified as proved developed, compared to approximately 100% and 55%, respectively, in both 2011 and 2010.  We operate approximately 97% of our reserves, based on the pre-tax PV-10 value of our proved developed producing reserves, and our reserve life index approximated 7.1 years at year-end 2012.  Natural gas sales accounted for nearly 100% of total operating revenues for this segment in 2012, 2011 and 2010.

The following table provides an overall and categorical summary of our oil and natural gas reserves, as of fiscal year-end 2012 based on average fiscal year prices, and our well count, net acreage and PV-10 as of December 31, 2012 and sets forth 2012 annual information related to production and capital investments for each of our operating areas:

(1)  We have no reserves from synthetic gas, synthetic oil or nonrenewable natural resources intended to be upgraded into synthetic gas or oil.  We used standard engineering and geoscience methods, or a combination of methodologies in determining estimates of material properties, including performance and test date analysis offset statistical analogy of performance data, volumetric evaluation, including analysis of petrophysical parameters (including porosity, net pay, fluid saturations (i.e., water, oil and gas) and permeability) in combination with estimated reservoir parameters (including reservoir temperature and pressure, formation depth and formation volume factors), geological analysis, including structure and isopach maps and seismic analysis, including review of 2-D and 3-D data to ascertain faults, closure and other factors. 

(2)  Our Total and Fayetteville Shale play capital investments exclude $15 million related to our drilling rig related equipment, sand facility and other equipment. 

(3)  Represents all producing wells, including wells in which we only have an overriding royalty interest, as of December 31, 2012.

(4)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 46,007 net acres in 2013, 183,824 net acres in 2014, which includes 153,863 net acres held on federal lands, and 39,071 net acres in 2015.  

(5)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 41,860 net acres in 2013, 13,467 net acres in 2014 and 3,835 net acres in 2015.

(6)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres in 2015.

(7)  Includes 123,442 net developed acres and 1,211 net undeveloped acres in the Arkoma Basin that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above. Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,200 net acres in 2013, 670 net acres in 2014 and 17,788 net acres in 2015.

(8)  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years, excluding New Brunswick, Canada and the LSBD area will be 1,120 net acres in 2013, 60,294 net acres in 2014 and 142,294 net acres in 2015.  With regard to the company’s acreage in New Brunswick, Canada, 2,518,518 net acres will expire in March 2015. We have applied for an additional 1-year option to extend our exploration license agreements and, if granted by the Province of New Brusnwick, this would extend our exploration license agreements until March 2016.  With regard to our acreage in the LSBD play, assuming successful wells are not drilled and leases are not extended, leasehold expiring over the next three years will be 68,023 net acres in 2013, 237,181 net acres in 2014 and 159,718 net acres in 2015.

(9)  Pre-tax PV-10 (a non-GAAP measure) is one measure of the value of a company’s proved reserves that we believe is used by securities analysts to compare relative values among peer companies without regard to income taxes.  The reconciling difference in pre-tax PV-10 and the after-tax PV-10, or standardized measure, is the discounted value of future income taxes on the estimated cash flows from our proved oil and natural gas reserves.

(10) Based upon pre-tax PV-10 of proved developed producing properties.

We refer you to Note 4 in our consolidated financial statements for a more detailed discussion of our proved gas and oil reserves as well as our standardized measure of discounted future net cash flows related to our proved gas and oil reserves.  We also refer you to the risk factor “Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a discussion of the risks inherent in utilization of standardized measures and estimated reserve data.

Proved Undeveloped Reserves

As of December 31, 2012, we had 821 Bcfe of proved undeveloped reserves, none of which were proved undeveloped reserves that remain undeveloped for five years or more after initially being disclosed by us.  During 2012, we invested $518 million in connection with converting 493.2 Bcfe or 19% of our proved undeveloped reserves as of December 31, 2011 into proved developed reserves and added 336.8 Bcfe of proved undeveloped reserve additions, primarily in the Fayetteville and Marcellus Shale plays. Our 2012 proved undeveloped reserve additions are expected to be developed and to begin to generate cash inflows over the next five years.  At December 31, 2011, we had 2,633 Bcfe of proved undeveloped reserves, none of which were proved undeveloped reserves that remained undeveloped for five years or more after initially being disclosed by us.  During 2011, we invested $509.3 million in connection with converting 403.3 Bcfe or 18% of our proved undeveloped reserves as of December 31, 2010 into proved developed reserves and added 847.8 Bcfe of proved undeveloped reserve additions, primarily in the Fayetteville Shale play.

The development of our proved undeveloped reserves will require us to make significant additional investments.  We expect that the development costs for our proved undeveloped reserves of 821 Bcfe as of December 31, 2012 will require us to invest an additional $698 million in order for those reserves to be brought to production.  Our ability to make the necessary investments to generate these cash inflows is subject to factors that may be beyond our control.  A significant decrease in price levels for an extended period of time could result in certain reserves no longer being economic to produce, leading to both lower proved reserves and cash flows.  We refer you to the risk factors “A substantial or extended decline in natural gas and oil prices would have a material adverse effect on us,” “We may have difficulty financing our planned capital investments, which could adversely affect our growth” and “Our level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.

Our Reserve Replacement

The ability of an E&P company to add new reserves to replace the reserves that are being depleted by its current production volumes is viewed by many investors as an indication of its long-term prospects.  The reserve replacement ratio, which we discuss below, is an important analytical measure used within the E&P industry by investors and peers to evaluate performance results.  There are limitations as to the usefulness of this measure as it does not reflect the type of reserves or the cost of adding the reserves or indicate the potential value of the reserve additions. 

In 2012, we replaced our production volumes with 919.5 Bcfe of proved reserve additions as a result of our drilling program, but also incurred net downward revisions of 2,088.2 Bcfe principally due to a decrease in the price of natural gas and to a lesser extent due to downward performance revisions of 336.4 Bcfe.  Of the reserve additions, 582.8 Bcfe were

proved developed and 336.7 Bcfe were proved undeveloped. The total downward reserve revisions were primarily impacted by the low commodity price environment in 2012 and to a lesser extent by downward performance revisions.   

In 2011, we replaced 299% of our production volumes with an increase of 1,459.4 Bcfe of proved gas and oil reserves as a result of our drilling program and net upward revisions of 33.7 Bcfe.  Of the reserve additions, 611.6 Bcfe were proved developed and 847.8 Bcfe were proved undeveloped. The upward reserve revisions during 2011 were primarily due to 102.6 Bcf in upward revisions related to the improved performance of wells in our Marcellus Shale play, partially offset by downward performance revisions of 27.5 Bcfe and 18.2 Bcfe in our East Texas and conventional Arkoma Basin operating areas, respectively.  We also had downward performance revisions in our Fayetteville Shale play of 14.0 Bcfe.  Additionally, our reserves decreased by 9.2 Bcfe due to a comparative decrease in the average gas price for 2011 as compared to 2010.  In addition, our reserves decreased by 37.3 Bcfe as a result of our sale of oil and natural gas leases and wells in 2011.

In 2010, we replaced 430% of our production volumes with an increase of 1,431.1 Bcfe of proved gas and oil reserves as a result of our drilling program and net upward revisions of 309.6 Bcfe.  Of the reserve additions, 698.0 Bcfe were proved developed and 733.2 Bcfe were proved undeveloped. The upward reserve revisions during 2010 were primarily due to 266.7 Bcf in upward revisions related to the improved performance of wells in our Fayetteville Shale play and positive reserve revisions of 78.4 Bcfe due to a comparative increase in the average gas price for 2010 as compared to 2009.  Additionally, we had net upward revisions of 2.7 Bcfe and 34.2 Bcf in our East Texas and conventional Arkoma Basin operating areas, respectively.  Additionally, our reserves decreased by 55.4 Bcfe as a result of our sale of oil and natural gas leases and wells in 2010.

For the period ending December 31, 2012, our three-year average reserve replacement ratio, including revisions, was 141%. Our reserve replacement ratio for 2012, excluding the effect of reserve revisions, was 163%, compared to 292% in 2011 and 354% in 2010. Excluding reserve revisions, our three-year average reserve replacement ratio is 259%.

Since 2005, the substantial majority of our reserve additions have been generated from our drilling program in the Fayetteville Shale play.  Over the past several years, the Marcellus Shale play has contributed an increasing amount to our reserve additions.  We expect our drilling programs in the Fayetteville Shale and Marcellus Shale plays to continue be the primary source of our reserve additions in the future; however, our ability to add reserves depends upon many factors that are beyond our control.  We refer you to the risk factors “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change” and “Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K and to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for a more detailed discussion of these factors and other risks.

Our Operations

Fayetteville Shale Play

Our Fayetteville Shale play is currently a primary focus of our E&P business.  The Fayetteville Shale is a Mississippian-age unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 550 feet and ranging in depth from 1,500 to 6,500 feet.  As of December 31, 2012, we held leases for approximately 913,502 net acres in the play area (310,135 net undeveloped acres, 479,925 net developed acres held by Fayetteville Shale production and 123,442 net acres held by conventional production in the traditional Fairway portion of the Arkoma Basin), compared to approximately 925,842 net acres at year-end 2011 and 915,884 net acres at year-end 2010.

Approximately 2,988 Bcf of our reserves at year-end 2012 were attributable to our Fayetteville Shale play, compared to approximately 5,104 Bcf at year-end 2011 and 4,345 Bcf at year-end 2010.  Our reserves in the Fayetteville Shale play decreased by 2,116 Bcf, which included net downward price revisions of 1,684 Bcf, 362 Bcf of downward revisions due to well performance, and production of 486 Bcf, partially offset by reserve additions of 415 Bcf.  Gross production from our operated wells in the Fayetteville Shale play increased from approximately 1,947 MMcf per day at the beginning of 2012 to approximately 2,090 MMcf per day by year-end.  Our net production from the Fayetteville Shale play was 485.5 Bcf in 2012, compared to 436.8 Bcf in 2011 and 350.2 Bcf in 2010.  In 2013, we estimate our net production from the Fayetteville Shale play will be in the range of 475 to 480 Bcf.

At year-end 2012, after excluding our acreage in the traditional Fairway and the federal acreage we hold in the Ozark Highlands Unit, approximately 80% of our 605,409 total net leasehold acres remaining in the Fayetteville Shale was held by production.  For more information about our acreage and well count, we refer you to “Properties” in Item 2 of Part 1 of

this Form 10-K.   Excluding our acreage in the traditional Fairway, our acreage position was obtained at an average cost of approximately $313 per acre and has an average royalty interest of 15%.  In 2013, we expect to earn 13 sections or approximately 5,700 net acres, representing 3% of our drilling program.  As of December 31, 2012, excluding our acreage in the traditional Fairway and our federal acreage, the undeveloped portion of our acreage had an average remaining lease term of 1.3 years.  We refer you to the risk factor “If we fail to drill all of the wells that are necessary to hold our acreage, the initial lease terms could expire, which would result in the loss of certain leasehold rights” in Item 1A of Part I of this Form 10-K. 

As of December 31, 2012, we had spud a total of 3,586 wells in the play since its commencement in 2004, 3,034 of which were operated by us and 552 of which were outside-operated wells.  Of the wells spud, 491 were in 2012, 650 were in 2011 and 658 were in 2010.  Of the wells spud in 2012, 485 were designated as horizontal wells.  At year-end 2012, 2,874 operated wells had been drilled and completed overall, including 2,783 horizontal wells.  Of the 2,783 horizontal wells, 2,765 wells were fracture stimulated using either slickwater or crosslinked gel stimulation treatments, or a combination thereof.

Over the past several years, we have seen continual improvement in our drilling practices in the Fayetteville Shale play.  Our operated horizontal wells had an average completed well cost of $2.5 million per well, average horizontal lateral length of 4,833 feet and average time to drill to total depth of 6.7 days from re-entry to re-entry in 2012.  This compares to an average completed operated well cost of $2.8 million per well, average horizontal lateral length of 4,836 feet and average time to drill to total depth of 7.9 days from re-entry to re-entry during 2011.  In 2010, our average completed operated well cost was $2.8 million per well with an average horizontal lateral length of 4,528 feet and average time to drill to total depth of 10.9 days from re-entry to re-entry.  The operated wells we placed on production during 2012 averaged initial production rates of 3,629 Mcf per day, compared to average initial production rates of 3,330 Mcf per day in 2011 and 3,364 Mcf per day in 2010.  The increase in initial production rates in 2012 was primarily due to the optimization of our drilling plan in the first quarter of 2012 toward areas in the field with the highest-return wells.  As a result, our average initial production rates on a per well basis were significantly higher, particularly during the last half of 2012.  The decrease in initial production rates in 2011 was primarily due to increased well density and locational differences in the mix of wells.  During 2012, we placed 60 operated wells on production with initial production rates that exceeded 5.0 MMcf per day.

Our total proved net reserves booked in the play at year-end 2012 were from a total of 3,508 locations, of which 3,175 were proved developed producing, 123 were proved developed non-producing and 210 were proved undeveloped.  Of the 3,508 locations, 3,468 were horizontal. The average gross proved reserves for the undeveloped wells included in our year-end 2012 was approximately 2.8 Bcf per well, compared to 2.4 Bcf per well at both year-end 2011 and year-end 2010.  Total proved net natural gas reserves booked in the play in 2011 totaled approximately 5,104 Bcf from a total of 4,376 locations, of which 2,735 were proved developed producing, 59 were proved developed non-producing and 1,582 were proved undeveloped.  Total proved net natural gas reserves booked in the play in 2010 totaled approximately 4,345 Bcf from a total of 3,682 locations, of which 2,120 were proved developed producing, 36 were proved developed non-producing and 1,526 were proved undeveloped. 

In 2012, we invested approximately $991 million in our Fayetteville Shale play, which included approximately $877 million to spud 491 wells, 453 of which we operated.  Included in our total capital investments in the play during 2012 was $110 million in capitalized costs and other expenses and $4 million for acquisition of properties.  In 2011, we invested approximately $1.3 billion in our Fayetteville Shale play, which included $1.2 billion to spud 650 wells, $10 million for acquisition of properties, and $132 million in capitalized costs and other expenses.  In 2010, we invested approximately $1.3 billion in our Fayetteville Shale play, which included $1.2 billion to spud 658 wells, $48 million for acquisition of properties and $111 million in capitalized costs and other expenses.  As of December 31, 2012, we had acquired approximately 1,324 square miles of 3-D seismic data, which provides us with seismic data on approximately 65% of our net acreage position in the Fayetteville Shale, excluding our acreage in the traditional Fairway portion of the Arkoma Basin.

In 2013, we plan to invest approximately $830 million in our Fayetteville Shale play, which includes participating in approximately 385 to 390 gross wells, all of which we plan to operate. 

We believe that our Fayetteville Shale acreage continues to have significant development potential.  Our strategy is to continue our development drilling, increase the amount of acreage we hold by production and determine the economic viability of the undrilled portion of our acreage.  Our drilling program with respect to our Fayetteville Shale play is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation methods and well spacing, the extent to which we can replicate the results of our most successful Fayetteville Shale wells in other Fayetteville Shale acreage and the natural gas commodity

price environment.  As we continue to gather data about the Fayetteville Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all. We refer you to the risk factor “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change” in Item 1A of Part I of this Form 10-K.

Marcellus Shale Play

We began leasing acreage in northeastern Pennsylvania in 2007 in an effort to gain a position in the emerging Marcellus Shale play.  As of December 31, 2012, we had approximately 176,298 net acres in Pennsylvania under which we believe the Marcellus Shale play is present (159,078 net undeveloped acres and 17,220 net developed acres held by production), compared to approximately 186,893 net acres at year-end of 2011 and 173,009 net acres at year-end 2010.  Our undeveloped acreage position as of December 31, 2012 had an average remaining lease term of three years and an average royalty interest of 15% and was obtained at an average cost of approximately $1,273 per acre. 

As of December 31, 2012, we had spud 160 operated wells, 72 of which were on production and 153 of which will be horizontal wells.  In 2012, we invested approximately $507 million in the Marcellus Shale play and spud 92 operated wells, resulting in reserve additions of 500 Bcf.  Of these 92 wells, 34 will be horizontal wells located in our Greenzweig area in Bradford County, 15 will be horizontal wells located in Lycoming County and the remaining 43 wells are located in our Price and Range Trust areas in Susquehanna County.  Our operated horizontal wells had an average completed well cost of $6.1 million per well, average horizontal lateral length of 4,070 feet and an average of 12 fracture stimulation stages in 2012.  This compares to an average completed operated well cost of $7.0 million per well, average horizontal lateral length of 4,223 feet and an average of 14 fracture stimulation stages in 2011.  In 2010, our average completed operated well cost was $6.0 million per well with an average horizontal lateral length of 3,602 feet and an average of nine fracture stimulation stages. Included in our total capital investments in the play during 2012 was approximately $400 million for drilling and completions, $24 million for acquisition of properties, $6 million for seismic and $77 million in facilities, capitalized costs and other expenses.  In 2011, we invested approximately $332 million in the Marcellus Shale play and spud 43 operated wells, resulting in net reserve additions and revisions of 327 Bcf.  In 2010, we invested approximately $118 million in the Marcellus Shale play and spud 21 operated wells, resulting in net reserve additions of 38 Bcf.

Approximately 816 Bcf of our total proved net reserves at year-end 2012 were attributable to the Marcellus Shale play.  The company had a total of 71 operated horizontal wells and one operated vertical well which were on production as of December 31, 2012, resulting in net production from this area of 53.6 Bcf in 2012, compared to 23.4 Bcf in 2011 and 1.0 Bcf in 2010.  Our reserves booked in the Marcellus Shale play included a total of 203 locations, of which 129 were proved developed producing, one was proved developed non-producing and 73 were proved undeveloped.  The average gross proved reserves for the undeveloped wells included in our year-end reserves for 2012 was approximately 7.6 Bcf per well, up from 7.5 Bcf per well at year-end 2011 and 3.0 Bcf per well in 2010. 

In 2013, we plan to invest approximately $705 million in the Marcellus Shale play and expect to participate in a total of 86 to 88 gross wells in 2013, all of which will be operated by us.  In 2013, we estimate our net production from the Marcellus Shale play will be in the range of 134 to 139 Bcf.  Our ability to bring our Marcellus Shale production to market will depend on a number of factors including the construction of and/or the availability of capacity on gathering systems and pipelines that we do not own.  We refer you to “Midstream Services — Gas Marketing” for a discussion of our gathering and transportation arrangements for the Marcellus Shale production and to the risk factor “Our ability to sell our natural gas and oil and/or to receive market prices for our production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others.” in Item 1A of Part I of this Form 10-K. 

We believe that our Marcellus Shale acreage has significant development potential.  Our drilling program with respect to our Marcellus Shale play is flexible and will be impacted by a number of factors, including the results of our horizontal drilling efforts, our ability to determine the most effective and economic fracture stimulation methods and well spacing and the natural gas commodity price environment.  As we continue to gather data about the Marcellus Shale, it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.  We refer you to the risk factor “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change” in Item 1A of Part I of this Form 10-K.

Ark-La-Tex

Our Ark-La-Tex division includes our conventional assets in the Arkoma Basin in Arkansas and Oklahoma and our conventional and unconventional assets in East Texas.  Production from these assets was 25.6 Bcfe in 2012, compared to 39.8 Bcfe in 2011 and 53.5 Bcfe in 2010.  The decline in production from these areas during 2012 and 2011 was primarily driven by asset dispositions as well as natural field production declines and lower capital investments in these areas since 2009.  In May 2012, we sold our oil and natural gas leases, wells and gathering equipment in approximately 19,800 net acres in the Overton Field in East Texas for approximately $166.0 million.  In May 2011, we sold the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,717 net acres for approximately $118.1 million.  In June 2010, we sold the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 20,063 net acres for approximately $357.8 million.  We expect these sales, together with our planned decrease in capital investments and the natural production decline in existing wells, to decrease our net production from the Ark-La-Tex division in 2013.  In 2012, we invested approximately $11 million in our Ark-La-Tex division and added new reserves of 3 Bcfe.  Total proved net reserves from these areas were approximately 213 Bcfe as of December 31, 2012, compared to 447 Bcfe at year-end 2011 and 554 Bcfe at year-end 2010.  In 2013, we expect to invest approximately $15 million in our Ark-La-Tex division.

New Ventures

We actively seek to find and develop new oil and natural gas plays with significant exploration and exploitation potential, which we refer to as “New Ventures.”  We have been focusing on both oil and natural gas unconventional plays, and the technological methods best suited to developing these plays, such as horizontal drilling and fracture stimulation techniques.  New Ventures prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria and may be located both inside and outside of the United States.  As of December 31, 2012, we held 3,819,128 net undeveloped acres in connection with our New Ventures prospects, of which 2,518,518 net acres were located in New Brunswick, Canada. This compares to 3,600,314 net undeveloped acres held at year-end 2011 and 3,009,643 net undeveloped acres held at year-end 2010.

In March 2010, we successfully bid for exclusive licenses from the Department of Natural Resources of the Province of New Brunswick, Canada to search and conduct an exploration program covering 2,518,518 net acres in the province in order to test new hydrocarbon basins.  As a condition under our licenses, we are required to make investments of approximately $47 million USD in the province by March 31, 2013.  In December 2012, we received two one-year extensions to our exploration license agreements which expire on March 16, 2014 and March 16, 2015, respectively.  Since 2010, we have conducted airborne gravity and magnetics surveys, surface geochemistry surveys and, as of December 31, 2012, had acquired 248 miles of 2-D seismic data.  While preliminary interpretation has already begun, in 2013 we intend to acquire an additional 130 additional miles of 2-D seismic data. Through December 31, 2012, we have invested approximately $25.8 million USD in our New Brunswick exploration program towards our commitment, which represents our first venture outside of the United States.

In July 2011, we announced that we would begin testing a new unconventional horizontal oil play targeting the LSBD formation, an unconventional oil reservoir that ranges in vertical depths from 8,000 to 11,000 feet and appears to be laterally extensive over a large area ranging in thickness from 300 to 550 feet.  As of December 31, 2012, we held approximately 504,486 net undeveloped acres in the area, obtained at an average cost of $419 per acre.  Our leases currently have approximately an 81% average net revenue interest and an average primary lease term of approximately four years, which may be extended for approximately four additional years.  We have drilled six operated wells in the play area to date, including two that are currently shut-in for further testing and one that was temporarily abandoned.  Three wells are currently producing, two of which are horizontal wells.  We are encouraged by our results to date and if our drilling program yields positive results, we expect that activity in the play could increase significantly over the next several years.

We have approximately 301,918 net acres in the Denver-Julesburg Basin in eastern Colorado where we have begun testing an unconventional oil play targeting middle and late Pennsylvanian to Permian-age carbonates and shales.  We have drilled a horizontal well and a vertical well, both of which are testing multiple intervals. 

We also have drilled a horizontal oil well in Sheridan County, Montana, targeting the Bakken and Three Forks objectives.  We are continuing to lease acreage and plan to permit and drill additional wells in the area in 2013.

While we believe that our New Ventures projects have significant exploration and exploitation potential, there can be no assurance that all prospects will result in viable projects or that we will not abandon our initial investments.  We refer you to the risk factors “The success of our New Ventures projects is subject to drilling and completion technique risks and

enhanced recovery methods.  Our drilling results may not meet our expectations for reserves or production and the value of our undeveloped New Venture acreage could decline,” and “Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns” in Item 1A of Part I of this Form 10-K.

Divestitures

In May 2012, we sold certain oil and natural gas leases, wells and gathering equipment in the Overton Field in East Texas for approximately $166 million.  The sale included approximately 19,800 net acres in Smith County, Texas.  Net production from the field was approximately 24 MMcfe per day as of the closing date and proved net reserves were approximately 143 Bcfe as of year-end 2011.

In May 2011, we sold certain oil and natural gas leases, wells and gathering equipment in East Texas for approximately $118.1 million.  The sale included only the producing rights to the Haynesville and Middle Bossier Shale intervals in approximately 9,717 net acres. The net production from the Haynesville and Middle Bossier Shale intervals in this acreage was approximately 7.0 MMcf per day and proved net reserves were approximately 37.1 Bcf when the sale was completed in May 2011.

Capital Investments

During 2012, we invested a total of $1.9 billion in our E&P business and participated in drilling 595 wells, 383  of which were successful, and 203 which were in progress at year-end.  Of the 203 wells in progress at year-end, 133 were located in our Fayetteville Shale play.  Of the approximately $1.9 billion invested in our E&P business in 2012, approximately $991 million was invested in our Fayetteville Shale play, $507 million in our Marcellus Shale play, $5 million in East Texas, $6 million in our conventional Arkoma Basin program and $337 million in New Ventures projects.

Of the $1.9 billion invested in 2012, approximately $1.4 billion was invested in exploratory and development drilling and workovers, $186 million for acquisition of properties, $10 million for seismic expenditures and $254 million in capitalized interest and other expenses.  Additionally, we invested approximately $15 million in our drilling rig related equipment, sand facility and other equipment.  In 2011, we invested approximately $2.0 billion in our primary E&P business activities and participated in drilling 708 wells. Of the $2.0 billion invested in 2011, approximately $1.5 billion was invested in exploratory and development drilling and workovers, $227 million for acquisition of properties, $30 million for seismic expenditures and $199 million in capitalized interest and expenses and other technology-related expenditures.  Additionally, we invested approximately $21 million in our drilling rig related equipment, sand facility, and other equipment.  In 2010, we invested approximately $1.8 billion in our primary E&P business activities and participated in drilling 713 wells.  Of the $1.8 billion invested in 2010, approximately $1.4 billion was invested in exploratory and development drilling and workovers, $200 million for acquisition of properties, $17 million for seismic expenditures and $172 million in capitalized interest and expenses and other technology-related expenditures.  Additionally, we invested approximately $13 million in drilling rig related and ancillary equipment.   

In 2013, we plan to invest approximately $1.8 billion in our E&P program and participate in drilling 480 to 490 gross wells, all of which we plan to operate.  The Fayetteville Shale play and Marcellus Shale play will be the primary focus of our capital investments, with planned investments of approximately $830 and $705 million, respectively.  Our planned 2013 capital investments also include approximately $235 million in unconventional exploration and New Ventures projects and $15 million in our Ark-La-Tex division. 

Of the $1.8 billion allocated to our 2013 E&P capital budget, approximately $1.3 billion will be invested in development and exploratory drilling, $14 million in seismic and other geological and geophysical expenditures, $109 million in acquisition of properties and $318 million in capitalized interest and expenses as well as equipment, facilities and technology-related expenditures.  We refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments” for additional discussion of the factors that could impact our planned capital investments in 2013.

Sales, Delivery Commitments and Customers

Sales. Our daily natural gas equivalent production averaged 1,543.7 MMcfe in 2012, compared to 1,370.0 MMcfe in 2011 and 1,108.8 MMcfe in 2010.  Total natural gas equivalent production was 565.0 Bcfe in 2012, up from 500.0 Bcfe in 2011 and 404.7 Bcfe in 2010.  Our natural gas production was 564.5 Bcf in 2012, compared to 499.4 Bcf in 2011 and 403.6 Bcf in 2010.  The increase in production in 2012 resulted primarily from a 48.7 Bcf increase in net production from our Fayetteville Shale play,  a  30.3 Bcf increase in net production from our Marcellus Shale play, and a 0.3 Bcfe increase in

net production from our New Ventures plays, which more than offset a combined 14.3 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.    The increase in production in 2011 resulted primarily from an 86.6 Bcf increase in production from the Fayetteville Shale play and a 22.4 Bcf increase in our Marcellus Shale play production, which more than offset a combined 13.7 Bcfe decrease in net production from our East Texas and Arkoma Basin properties.  We also produced 83,000 barrels of oil in 2012, compared to 97,000 barrels of oil in 2011 and 171,000 barrels of oil in 2010.  Our oil production has decreased between 2012 and 2011 primarily due to the divestiture of certain East Texas properties and the natural production decline in existing wells.  For 2013, we are targeting total net natural gas and oil production of approximately 628 to 640 Bcfe, which represents a growth rate of approximately 12% over our 2012 production volumes, using midpoints.

Sales of natural gas and oil production are conducted under contracts that reflect current prices and are subject to seasonal price swings. We are unable to predict changes in the market demand and price for natural gas, including changes that may be induced by the effects of weather on demand for our production.  We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and oil production in order to support certain desired levels of cash flow and to minimize the impact of price fluctuations.  Our policies prohibit speculation with derivatives and limit swap agreements to counterparties with appropriate credit standings. As of December 31, 2012, we had New York Mercantile Exchange, or NYMEX commodity price hedges in place on 185.6 Bcf, or approximately 29% of our targeted 2013 natural gas production and 18.3 Bcf of our expected 2014 natural gas production.  We intend to hedge additional future production volumes to the extent natural gas prices rise to levels that we believe will achieve certain desired levels of cash flow.  We refer you to Item 7A of this Form 10-K, “Quantitative and Qualitative Disclosures about Market Risks,” for further information regarding our hedge position as of December 31, 2012.

Including the effect of hedges, we realized an average wellhead price of $3.44 per Mcf for our natural gas production in 2012, compared to $4.19 per Mcf in 2011 and $4.64 per Mcf in 2010.  Our hedging activities increased our average realized natural gas sales price $1.10 per Mcf in 2012,  $0.63 per Mcf in 2011 and $0.71 per Mcf in 2010.  Our average oil price realized was $101.54 per barrel in 2012, compared to $94.08 per barrel in 2011 and $76.84 per barrel in 2010.  None of our oil production was hedged during 2012, 2011 or 2010. 

During 2012, the average price received for our natural gas production, excluding the impact of hedges, was approximately $0.45 Mcf lower than average NYMEX prices.  Assuming a NYMEX commodity price for 2013 of $3.50 per Mcf of natural gas, we expect to receive an average sales price for our natural gas production $0.50 to $0.55 per Mcf below the NYMEX Henry Hub average settlement price, excluding the impact of hedges. In 2013, we expect to incur average third-party transportation charges in the range of $0.35 to $0.40 per Mcf and average fuel charges in the range of 0.35% to 0.50% of our sales price for natural gas and we expect our average basis differential to be approximately $0.10 per Mcf less than NYMEX.

Delivery Commitments. As of February 1, 2013, we had natural gas delivery commitments of 337 Bcf in 2013 and 86 Bcf in 2014 under existing agreements.  These commitments require the delivery of natural gas in Arkansas, Pennsylvania and Texas.   These amounts are well below our forecasted 2013 and anticipated 2014 production from our available reserves in our Fayetteville Shale, Marcellus Shale and East Texas operations, which are not subject to any priorities or curtailments that may affect quantities delivered to our customers or any priority allocations or price limitations imposed by federal or state regulatory agencies, or any other factors beyond our control that may affect our ability to meet our contractual obligations other than those discussed in Item 1A. “Risk Factors.”  We expect to be able to fulfill all of our short-term or long-term contractual obligations to provide natural gas from our own production of available reserves, however, if we are unable to do so, we may have to purchase natural gas at market to fulfill our obligations.

Customers. Our customers include major energy companies, utilities and industrial consumers of natural gas. During the years ended December 31, 2012, 2011 and 2010, no single third-party customer accounted for 10% or more of our consolidated revenues.

Impact of Federal Regulation of Sales of Natural Gas and Oil

The natural gas industry historically has been heavily regulated and from time to time proposals are introduced by Congress and the FERC and judicial decisions are rendered that impact the conduct of business in the natural gas industry.  There can be no assurance that the current, less stringent regulatory approach pursued by the FERC and Congress will continue. We refer you to “Other Items — Environmental Matters” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation on our business.

Competition

All phases of the oil and natural gas industry are highly competitive.  We compete in the acquisition of properties, the search for and development of reserves, the production and sale of natural gas and oil and the securing of labor and equipment required to conduct our operations.  Our competitors include major oil and natural gas companies, other independent oil and natural gas companies and individual producers and operators.  Many of these competitors have financial and other resources that substantially exceed those available to us.

Competition in Arkansas has increased in recent years due largely to the development of improved access to interstate pipelines and our discovery of the Fayetteville Shale play. While improved intrastate and interstate pipeline transportation in Arkansas has increased our access to markets for our natural gas production, these markets are also served by a number of other suppliers.  Consequently, we will encounter competition that may affect both the price we receive and contract terms we must offer. Outside Arkansas, we are less established and face competition from a larger number of other producers.

We cannot predict whether and to what extent any market reforms initiated by the FERC or any new energy legislation will achieve the goal of increasing competition, lessening preferential treatment and enhancing transparency in markets in which our natural gas is sold.  However, we do not believe that we will be disproportionately affected as compared to other natural gas producers and marketers by any action taken by the FERC or any other legislative body.

Regulation of Hydraulic Fracturing

We utilize hydraulic fracturing in our E&P operations as a means of maximizing the productivity of our wells.  It is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense subsurface rock formations. The knowledge and expertise in fracturing techniques we have developed through our operations in the Fayetteville Shale play are being utilized in our other operating areas, currently including our Marcellus Shale acreage and, in the near future, expected to include our exploration programs in New Brunswick, Canada. Successful hydraulic fracturing techniques are also expected to be critical to the development of our recently announced unconventional horizontal oil play targeting the LSBD formation in Arkansas and Louisiana and potentially other New Venture areas.  Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. In our Fayetteville Shale and Marcellus Shale plays, the fracturing fluids we use are comprised of over 99.9% water and sand.  The remaining 0.1% is comprised of small quantities of additives which contain chemical compounds such as hydrochloric acid, phosphoric acid, glutaraldehyde and sodium chloride which is used in common household products.

In the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing practices in the United States and Canada.  In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions but there have recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.

The Environmental Protection Agency, or EPA, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority. In addition, the EPA issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards, or NSPS, and National Emission Standards for Hazardous Air Pollutants, or NESHAPS programs. The EPA final rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the reduced emission completion, or REC techniques developed in the EPA's Natural Gas STAR program. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the final regulations under NESHAPS include maximum achievable control technology, or MACT, standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Based on our current operations and practices, management believes, such newly promulgated rules will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.

In October 2011, the EPA also announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to publicly owned treatment works or POTWs. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.

In addition to the EPA’s efforts, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and while initial results were expected to be available by late 2012 and final results by 2014, to date the EPA has not released any results from the study. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Certain states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.  In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

In the Province of New Brunswick in Canada there are presently no hydraulic fracturing regulations, however the provincial government has been working on a new comprehensive regulatory framework that is expected to be released to the public in late 2013.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows. We refer you to the risk factor “Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage” in Item 1A of Part I of this Form 10-K.

Midstream Services

We believe our Midstream Services segment is well-positioned to complement our E&P initiatives and to compete with other midstream providers for unaffiliated business.  We generate revenue from gathering fees associated with the transportation of natural gas to market and through the marketing of natural gas.  Our gathering assets support our E&P operations and are currently concentrated in our Fayetteville Shale play in Arkansas and our Marcellus Shale play in Pennsylvania.

Our operating income from this segment was $294.3 million on revenues of $2.4 billion in 2012, compared to $248.0 million on revenues of $2.9 billion in 2011 and $191.6 million on revenues of $2.5 billion in 2010.  Revenues increased in 2012 and 2011 primarily due to increased gathering revenues and increased volumes marketed.  EBITDA generated by our Midstream Services segment was $338.8 million in 2012, compared to $285.1 million in 2011 and $220.5 million in 2010.  The increases in 2012 and 2011 operating income and EBITDA were primarily due to increased gathering revenues and margins, partially offset by increased operating costs and expenses.  We expect that the operating income and EBITDA of our Midstream Services segment will increase over the next few years as we continue to develop our Fayetteville Shale and Marcellus Shale acreage positions.  EBITDA is a non-GAAP measure.  We refer you to “Business — Other Items — Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA to net income (loss) attributable to Southwestern Energy. 

Gas Gathering

We engage in gas gathering activities through our gathering subsidiaries, DeSoto Gathering and Angelina Gathering. DeSoto Gathering engages in gathering activities in Arkansas primarily related to the development of our Fayetteville Shale play.  In 2012, we invested approximately $165.0 million related to these activities and had gathering revenues of

$474.0 million, compared to $160.8 million invested and revenues of $408.2 million in 2011 and $271.3 million invested and revenues of $316.0 million in 2010. 

DeSoto Gathering is expanding its network of gathering lines and facilities throughout the Fayetteville Shale play area. During 2012, DeSoto Gathering gathered approximately 780.7 Bcf of natural gas volumes in the Fayetteville Shale play area, including 56.0 Bcf of natural gas from third-party operated wells.  During 2011, DeSoto Gathering gathered approximately 703.6 Bcf of natural gas volumes in the Fayetteville Shale play area, including 57.4 Bcf of natural gas from third-party wells. In 2010, DeSoto Gathering gathered approximately 562.6 Bcf of natural gas volumes in the Fayetteville Shale play area, including 56.6 Bcf of natural gas from third-party wells.  The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Fayetteville Shale play.  At the end of 2012, DeSoto Gathering had approximately 1,852 miles of pipe from the individual wellheads to the transmission lines and compression equipment representing in aggregate approximately 531,470 horsepower had been installed at 61 central point gathering facilities in the field. 

Angelina Gathering currently engages in gathering activities in Pennsylvania and in East Texas.  Angelina Gathering is expanding its network of gathering lines and facilities throughout the Marcellus Shale play area. During 2012,  Angelina Gathering gathered approximately 64.7 Bcf of natural gas volumes in the Marcellus Shale play and East Texas areas, including 0.1 Bcf of natural gas from third-party operated wells.  During 2011,  Angelina Gathering gathered approximately 42.1 Bcf of natural gas volumes in the Marcellus Shale play and East Texas areas, including 0.2 Bcf of natural gas from third-party wells. In 2010,  Angelina Gathering gathered approximately 25.6 Bcf of natural gas volumes in the Marcellus Shale play and East Texas areas, including 0.7 Bcf of natural gas from third-party wells.  The increase in volumes gathered over the past three years was primarily due to our growing production volumes from the Marcellus Shale play.  At year-end 2012, Angelina Gathering had approximately 57 miles of pipe in Pennsylvania and 25 miles of pipe in Texas.  As of December 31, 2012, compression equipment representing in aggregate approximately 28,195 horsepower had also been installed at 3 central point gathering facilities in Pennsylvania. 

Gas Marketing

Our gas marketing subsidiary, SES, allows us to capture downstream opportunities related to marketing and transportation of natural gas. SES purchases natural gas and sells it to end-users, manages basis risk and marketing portfolio and acquires transportation rights on third-party pipelines.  Our current marketing operations primarily relate to the marketing of our own natural gas production and some third-party natural gas.  During 2012, we marketed 676.2 Bcf of natural gas, compared to 611.4 Bcf in 2011 and 495.8 Bcf in 2010.  Of the total volumes marketed, production from our E&P operated wells accounted for 95% in 2012, compared to 94% in 2011 and 95% in 2010.

SES is a “foundation shipper” on two pipeline projects serving the Fayetteville Shale play growth, the Fayetteville Express Pipeline LLC, or FEP, a 2.0 Bcf per day pipeline that is jointly owned by Kinder Morgan Energy Partners, L.P. and Energy Transfer Partners, L.P., and two pipeline laterals called the Fayetteville and Greenville Laterals, which have already been constructed by Texas Gas Transmission, LLC, or Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP, or Boardwalk Pipeline Partners.  FEP was placed in-service in January 2011.  SES has a maximum aggregate commitment of 1,200,000 Dekatherms per day for an initial term of ten years from the in-service date.  SES has maximum aggregate commitments of 800,000 MMBtu per day on the Fayetteville Lateral and 640,000 MMBtu per day on the Greenville Lateral.

Prior to the commencement of service on the Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline, the majority of our natural gas from the Arkoma Basin was moved to markets in the Midwest and was sold primarily based on two indices, “NGPL TexOk” and “Centerpoint East.”  The Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline allow us to transport our natural gas to markets in the eastern United States and interconnect with Texas Gas Zone 1, Tennessee Gas Pipeline 100, Trunkline Zone 1A, ANR, Tennessee Gas Pipeline 800, Columbia Gulf Mainline, TETCO M1 30" and Sonat price indices.  We rely in part upon the Fayetteville and Greenville Laterals and the Fayetteville Express Pipeline to service our increased production from the Fayetteville Shale play. 

During 2011 and 2012, SES entered into a number of short- and long-term firm transportation service and gathering agreements in support of our growing Marcellus Shale operations in Pennsylvania. In March 2011, SES entered into a precedent agreement with Millennium Pipeline Company, L.L.C. pursuant to which it will enter into short- and long-term firm natural gas transportation services on Millennium’s existing system.  Expansions of the system are expected to be in-service by the second quarter of 2013.  In June 2011, SES entered into separate 15 year agreements with each of Bluestone Pipeline Company of Pennsylvania, LLC (“Bluestone Gathering”), and Susquehanna Gathering Company I, LLC, both wholly owned subsidiaries of DTE Pipeline Company, an affiliate of DTE Energy Company. Bluestone Gathering committed to build and operate a natural gas gathering system in Susquehanna County, Pennsylvania and Broome County,

New York, and provide gathering services to SES in support of a portion of our future Marcellus Shale natural gas production.  This gathering system was initially placed into service in November 2012 and is expected to be fully completed during the first quarter of 2013. Susquehanna Gathering Company I, LLC. committed to build and operate gathering infrastructure from well pad receipt locations for deliveries into the Bluestone Gathering system as well as other potential field delivery points. This system was first placed into service November 2012 and will be constructed as necessary to support the company’s activities primarily in Susquehanna County.  SES also executed firm transportation agreements with Tennessee Gas Pipeline Company (“TGP”) that increase our ability to move our Marcellus Shale natural gas production in the short term to market as well as a precedent agreement for an expansion project with a projected in-service date of November 2013 pursuant to which SES has subscribed for 100,000 Dekatherm per day of capacity.  TGP’s expansion project will expand its 300 Line in Pennsylvania to provide natural gas transportation from the Marcellus Shale supply area to existing delivery points on the TGP system.  TGP filed a certificate application for the project with the Federal Energy Regulatory Commission issued a certificate on August 9, 2012.  Construction would begin in second quarter 2013, with a projected November 1, 2013 in-service date.  On March 23, 2012, SES entered into a precedent agreement with Constitution Pipeline Co. LLC for a proposed 121-mile pipeline connecting to the Iroquois Gas Transmission and Tennessee Gas Pipeline systems in Schoharie County, New York. Subject to the receipt of regulatory approvals and satisfaction of other conditions, SES agreed to enter a 15 year firm transportation agreement with a total capacity of 150 MMcf per day on this project.  The project is expected to be in service by the second quarter of 2015.  In March 2012, SES entered into a firm transportation agreement with TGP to utilize existing transportation capacity to various delivery points on TGP’s system.  SES agreed to enter into a 10 year firm transportation agreement with a total capacity of 130 MMcf per day on this project.  The project went into service in November 2012.  We have provided certain guarantees of a portion of SES’s obligations under these agreements.  We refer you to the risk factor “If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce our projected supply of natural gas, our investments in our gathering operations could be lost.  In addition, our commitments for transportation on third-party pipelines and gathering systems could make the sale of our natural gas uneconomic, which could have an adverse effect on our results of operations financial condition and cash flows.”    

As of December 31, 2012, SES’s and SEPCO’s obligations for demand and similar charges under the firm transportation agreements and gathering agreements totaled approximately $2.8 billion and the Company has guarantee obligations of up to $100.0 million of that amount.   

Competition

Our gas gathering and marketing activities compete with numerous other companies offering the same services, many of which possess larger financial and other resources than we have.  Some of these competitors are other producers and affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users. Other factors affecting competition are the cost and availability of alternative fuels, the level of consumer demand and the cost of and proximity to pipelines and other transportation facilities.  We believe that our ability to compete effectively within the marketing segment in the future depends upon establishing and maintaining strong relationships with producers and end-users.

Regulation

We refer you to “Other Items — Environmental Matters” and the risk factor “We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future” in Item 1A of Part I of this Form 10-K for a discussion of the impact of government regulation on our Midstream Services business.

In November 2008, the FERC issued a Final Rule in Order No. 720, which requires, in relevant part, major non-interstate natural gas pipelines to post, on a daily basis, specific scheduled flow information at each receipt or delivery point with a design capacity of 15,000 MMBtu per day or more. A “major non-interstate pipeline” is a pipeline that is not classified as a natural gas company under the Natural Gas Act of 1938, or NGA, and delivers on average more than 50 million MMBtu of natural gas annually over a three-year period.  Our gathering system in Arkansas constitutes a “major non-interstate pipeline” under Order No. 720. In October 2011, the United States Court of Appeals for the Fifth Circuit issued a decision granting the Texas Pipeline Association and the Railroad Commission’s petition for review and vacating FERC’s Order Nos. 720 and 720-A.  In its order, the 5th Circuit held that Order Nos. 720 and 720-A exceeded the scope of FERC’s authority under the NGA and that the FERC cannot require a non-interstate pipeline to post capacity and scheduling information. Notwithstanding the ruling, Order No. 720 remains in effect.  Compliance with Order No. 720 has not had a material adverse impact on our operations.

Other

Our other operations have primarily consisted of real estate development activities concentrated on tracts of land located in Arkansas.  During 2012, we sold our office complex in Fayetteville, Arkansas, our interest in approximately 9.5 acres of real estate near the Fayetteville complex and our office complex in Conway, Arkansas for approximately $32.2 million.  Subsequently, we leased back our Conway complex from the buyer for a 15 year term.  We also purchased 26 acres near The Woodlands, Texas for a future office site.  There were no sales of commercial real estate in 2011 or 2010. 

Our sand mining operations, in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-K.

Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income (loss) attributable to Southwestern Energy plus interest, income tax expense, impairment of natural gas and oil properties, and depreciation, depletion and amortization.  We have included information concerning EBITDA in this Form 10-K because it is used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in our industry.  EBITDA should not be considered in isolation or as a substitute for net income (loss) attributable to Southwestern Energy, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles in the United States, or GAAP, or as a measure of our profitability or liquidity.  EBITDA as defined above may not be comparable to similarly titled measures of other companies.

We believe that net income (loss) attributable to Southwestern Energy is the financial measure calculated and presented in accordance with GAAP that is most directly comparable to EBITDA as defined.  The following table reconciles EBITDA, as defined, with net income (loss) attributable to Southwestern Energy for the years-ended December 31, 2012, 2011 and 2010:

Environmental Regulation  

Our operations are subject to regulation in the jurisdictions in which we operate.  We have operations in the United States and, to a much lesser extent, in Canada.  In the United States, we are subject to numerous federal, state and local

laws and regulations including the Comprehensive Environmental Response, Compensation and Liability Act, or the CERCLA, the Clean Water Act, the Clean Air Act and similar state statutes.  These laws and regulations require permits for drilling wells and the maintenance of bonding requirements in order to drill or operate wells and also regulate the spacing and location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells and the prevention and cleanup of pollutants and other matters.  We maintain insurance against costs of clean-up operations, but we are not fully insured against all such risks.  Although future environmental obligations are not expected to have a material impact on the results of our operations or financial condition, there can be no assurance that future developments, such as increasingly stringent environmental laws or enforcement thereof, will not cause us to incur material environmental liabilities or costs.

Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal fines and penalties and the imposition of injunctive relief.  Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as those in the natural gas and oil industry in general.  Although we believe that we are in substantial compliance with applicable environmental laws and regulations and that continued compliance with existing requirements will not have a material adverse impact on us, there can be no assurance that this will continue in the future.  

The Oil Pollution Act, as amended, or the OPA, and regulations thereunder impose a variety of requirements on “responsible parties” related to the prevention of oil spills and liability for damages resulting from such spills in United States’ waters.  A “responsible party” includes the owner or operator of an onshore facility, pipeline or vessel, or the lessee or permittee of the area in which an offshore facility is located.  OPA assigns liability to each responsible party for oil cleanup costs and a variety of public and private damages.  While liability limits apply in some circumstances, a party cannot take advantage of liability limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation.  If the party fails to report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.  Few defenses exist to the liability imposed by OPA.  OPA imposes ongoing requirements on a responsible party, including the preparation of oil spill response plans and proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill. 

CERCLA, also known as the “Superfund law,” imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to be responsible for the release of a “hazardous substance” into the environment.  These persons include the owner or operator of the disposal site or sites where the release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances found at the site. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. 

The Resource Conservation and Recovery Act, as amended, or the RCRA, generally does not regulate wastes generated by the exploration and production of natural gas and oil.  The RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of oil, natural gas or geothermal energy.”  However, legislation has been proposed in Congress from time to time that would reclassify certain natural gas and oil exploration and production wastes as “hazardous wastes,” which would make the reclassified wastes subject to much more stringent handling, disposal and clean-up requirements. If such legislation were to be enacted, it could have a significant impact on our operating costs, as well as the natural gas and oil industry in general.  Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.

Our activities in Canada have to date been limited to certain geological and geophysical activities that are not subject to extensive environmental regulation.  Once we begin exploration activities in New Brunswick, we will be subject to federal, provincial and local environmental regulations that we believe require compliance efforts comparable to those required in the United States.

We own or lease, and have in the past owned or leased, onshore properties that for many years have been used for or associated with the exploration and production of natural gas and oil.  Although we have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us on or under other locations where such wastes have been taken for disposal. In addition, a portion of these properties have been operated by third parties whose treatment and disposal or release of wastes was not under our control.  These properties and the wastes disposed thereon may be subject to CERCLA, the Clean Water Act, the RCRA and analogous state laws.  Under such laws, we could be required to remove or

remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination by prior owners or operators), or to perform remedial plugging or closure operations to prevent future contamination.

The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters.  Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands.  The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters.  Although the costs to comply with zero discharge mandates under federal or state law may be significant, the entire industry is expected to experience similar costs and we believe that these costs will not have a material adverse impact on our results of operations or financial position. The EPA has adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans.

In the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing practices at the federal, state and local levels of government although hydraulic fracturing is typically regulated by state oil and natural gas commissions.  The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority.  In addition to the EPA’s efforts, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. For a discussion of hydraulic fracturing related environmental legislation, we refer you to “Exploration and Production — Regulation of Hydraulic Fracturing” and the risk factor “Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or prevent us realizing the value of undeveloped acreage” in Item 1A of Part I of this Form 10-K.

Employees

As of December 31, 2012, we had 2,427 total employees.  None of our employees were covered by a collective bargaining agreement at year-end 2012.  We believe that our relationships with our employees are good.

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below apply to the indicated terms as used in this Form 10-K. All natural gas reserves and production reported in this Form 10-K are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit.

“Acquisition of properties” Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs, and other costs incurred in acquiring properties. For additional information, see the SEC’s definition in Rule 4-10(a) (1) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Analogous reservoir”  Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an “analogous reservoir” refers to a reservoir that shares the following characteristics with the reservoir of interest:

For additional information, see the SEC’s definition in Rule 4-10(a) (2) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Available reserves”  Estimates of the amounts of oil and natural gas which the registrant can produce from current proved developed reserves using presently installed equipment under existing economic and operating conditions and an estimate of amounts that others can deliver to the registrant under long-term contracts or agreements on a per-day, per-month, or per-year basis.  For additional information, see the SEC’s definition in Item 1207(d) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Bbl”  One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to oil or other liquid hydrocarbons.

“Bcf”  One billion cubic feet of natural gas.

“Bcfe”  One billion cubic feet of natural gas equivalent.  Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“Btu”  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

“Dekatherm”  One million British thermal units (Btu).

“Deterministic estimate” The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure. For additional information, see the SEC’s definition in Rule 4-10(a) (5) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Developed oil and gas reserves” Developed oil and natural gas reserves are reserves of any category that can be expected to be recovered:

For additional information, see the SEC’s definition in Rule 4-10(a) (6) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Development costs” Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and natural gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

For additional information, see the SEC’s definition in Rule 4-10(a) (7) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Development project” A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project. For additional information, see the SEC’s definition in Rule 4-10(a) (8) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Development well”  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. For additional information, see the SEC’s definition in Rule 4-10(a) (9) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Downspacing”   The process of drilling additional wells within a defined producing area to increase recovery of natural gas and oil from a known reservoir.

“EBITDA”  Represents net income (loss) attributable to Southwestern Energy common stock plus interest, income taxes, depreciation, depletion and amortization and the impairment of natural gas and oil properties.  We refer you to “Business —  Other Items —  Reconciliation of Non-GAAP Measures” in Item 1 of Part I of this Form 10-K for a table that reconciles EBITDA with our net income (loss) attributable to Southwestern Energy from our audited financial statements.

“Economically producible” The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. For additional information, see the SEC’s definition in Rule 4-10(a) (10) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Estimated ultimate recovery (EUR)” Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date. For additional information, see the SEC’s definition in Rule 4-10(a) (11) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Exploitation”  The development of a reservoir to extract its gas and/or oil.

“Exploratory well”  An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.  For additional information, see the SEC’s definition in Rule 4-10(a) (13) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Field”  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious, strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. For additional information, see the SEC’s definition in Rule 4-10(a) (15) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Fracture stimulation” A process whereby fluids mixed with proppants are injected into a wellbore under pressure in order to fracture, or crack open, reservoir rock, thereby allowing oil and/or natural gas trapped in the reservoir rock to travel through the fractures and into the well for production.

“Gross well or acre”  A well or acre in which the registrant owns a working interest. The number of gross wells is the total number of wells in which the registrant owns a working interest. For additional information, see the SEC's definition in Item 1208(c)(1) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Gross working interest”  Gross working interest is the working interest in a given property plus the proportionate share of any royalty interest, including overriding royalty interest, associated with the working interest.

“Infill drilling”  Drilling wells in between established producing wells to increase recovery of natural gas and oil from a known reservoir.

“MBbls”  One thousand barrels of oil or other liquid hydrocarbons.

“Mcf”  One thousand cubic feet of natural gas.

“Mcfe”  One thousand cubic feet of natural gas equivalent.  Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“MMBbls”  One million barrels of oil or other liquid hydrocarbons.

“MMBtu”  One million British thermal units (Btu).

“MMcf”  One million cubic feet of natural gas.

“MMcfe”  One million cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“Net revenue interest”  Economic interest remaining after deducting all royalty interests, overriding royalty interests and other burdens from the working interest ownership.

“Net well or acre”  Deemed to exist when the sum of fractional ownership working interests in gross wells or acres equals one. The number of net wells or acres is the sum of the fractional working interests owned in gross wells or acres expressed as whole numbers and fractions of whole numbers. For additional information, see the SEC's definition in Item 1208(c)(2) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.  

“NGL”  Natural gas liquids.

“NYMEX”  The New York Mercantile Exchange.

“Operating interest”  An interest in natural gas and oil that is burdened with the cost of development and operation of the property.

“Overriding royalty interest”  A fractional, undivided interest or right to production or revenues, free of costs, of a lessee with respect to an oil or natural gas well, that overrides a working interest.

“Play”  A term applied to a portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential oil and natural gas reserves.

“Present Value Index” or “PVI”  A measure that is computed for projects by dividing the dollars invested into the PV-10 resulting from the investment.

“Probabilistic estimate” The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence. For additional information, see

the SEC’s definition in Rule 4-10(a) (19) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Producing property”  A natural gas and oil property with existing production.

“Productive wells”  Producing wells and wells mechanically capable of production. For additional information, see the SEC's definition in Item 1208(c)(3) of Regulation S-K, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Proppant”  Sized particles mixed with fracturing fluid to hold fractures open after a hydraulic fracturing treatment.  In addition to naturally occurring sand grains, man-made or specially engineered proppants, such as resin-coated sand or high-strength ceramic materials like sintered bauxite, may also be used.  Proppant materials are carefully sorted for size and sphericity to provide an efficient conduit for production of fluid from the reservoir to the wellbore.

“Proved developed producing” Proved developed reserves that can be expected to be recovered from a reservoir that is currently producing through existing wells.

“Proved developed reserves”  Proved gas and oil that are also developed gas and oil reserves.

“Proved oil and gas reserves”   Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. Also referred to as “proved reserves.” For additional information, see the SEC’s definition in Rule 4-10(a) (22) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Proved reserves”  See “proved oil and gas reserves.”

“Proved undeveloped reserves”  Proved oil and gas reserves that are also undeveloped oil and gas reserves.

“PV-10”  When used with respect to natural gas and oil reserves, PV-10 means the estimated future gross revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.  Also referred to as “present value.” After-tax PV-10 is also referred to as “standardized measure” and is net of future income tax expense.

“Reserve life index”  The quotient resulting from dividing total reserves by annual production and typically expressed in years.

“Reserve replacement ratio”  The sum of the estimated net proved reserves added through discoveries, extensions, infill drilling and acquisitions (which may include or exclude reserve revisions of previous estimates) for a specified period of time divided by production for that same period of time.

“Reservoir” A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. For additional information, see the SEC’s definition in Rule 4-10(a) (27) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Royalty interest”  An interest in a natural gas and oil property entitling the owner to a share of oil or natural gas production free of production costs. 

“Tcf”  One trillion cubic feet of natural gas.

“Tcfe”  One trillion cubic feet of natural gas equivalent. Determined using the ratio of one barrel of oil to six Mcf of natural gas.

“Unconventional play”  A term used in the natural gas and oil industry to refer to a play in which the targeted reservoirs generally fall into one of three categories: (1) tight sands, (2) coal beds, or (3) natural gas shales. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require fracture stimulation treatments or other special recovery processes in order to produce economic flow rates.

“Undeveloped acreage” Those leased acres on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil or gas regardless of whether such acreage contains proved reserves. For additional information, see the SEC's definition in Item 1208(c)(4) of Regulation S-K, a link for which is available at the SEC's website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Undeveloped oil and natural gas reserves” Undeveloped oil and natural gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.  Also referred to as “undeveloped reserves.”  For additional information, see the SEC’s definition in Rule 4-10(a) (31) of Regulation S-X, a link for which is available at the SEC’s website, http://www.sec.gov/divisions/corpfin/ecfrlinks.shtml.

“Undeveloped reserves” See “undeveloped oil and natural gas reserves.”

“USD” United States Dollar.

“Well spacing” The regulation of the number and location of wells over an oil or natural gas reservoir, as a conservation measure.  Well spacing is normally accomplished by order of the regulatory conservation commission in the applicable jurisdiction.  The order may be statewide in its application (subject to change for local conditions) or it may be entered for each field after its discovery. In the operational context, “well spacing” refers to the area attributable between producing wells within the scope of what is permitted under a regulatory order.

“Working interest” An operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and to receive a share of production.

“Workovers” Operations on a producing well to restore or increase production.

“WTI” West Texas Intermediate, the benchmark oil in the United States.

ITEM 1A.  RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating our business and future prospects.  The risk factors described below represent what we believe are the most significant risk factors with respect to us and our business.  In assessing the risks relating to our business, investors should also read the other information included in this Form 10-K, including our financial statements and the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Cautionary Statement about Forward-Looking Statements.”

A substantial or extended decline in natural gas and oil prices would have a material adverse effect on us.

In the first half of 2008, natural gas and oil prices were at or near their highest historical levels but have subsequently declined significantly.  Natural gas prices declined in 2012 as compared with 2011.  Further significant decline in natural gas and oil prices would have a material adverse effect on our financial position, our results of operations, our access to capital and the quantities of natural gas and oil that may be economically produced by us.  A significant decrease in price levels for an extended period would negatively affect us in several ways including the following:

Consequently, our revenues and profitability would suffer.

Lower natural gas and oil prices and/or increased development costs may cause us to record ceiling test write-downs.  

We use the full cost method of accounting for our natural gas and oil operations.  Accordingly, we capitalize the cost to acquire, explore for and develop natural gas and oil properties.  Under the full cost accounting rules of the SEC, the capitalized costs of natural gas and oil properties – net of accumulated depreciation, depletion and amortization, and deferred income taxes – may not exceed a “ceiling limit” on a country-by-country basis.  This is equal to the present value of estimated future net cash flows from proved natural gas and oil reserves, discounted at 10%, plus the lower of cost or fair value of unproved properties included in the costs being amortized, net of related tax effects.

These rules generally require pricing future natural gas and oil production at the unescalated natural gas and oil prices in effect at the end of each fiscal quarter, including the impact of derivatives qualifying as cash flow hedges, utilizing the average price in the 12-month period prior to the end of each fiscal quarter.  The average price for this period is defined as the unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices were defined by contractual arrangements, excluding escalations based upon future conditions. These rules also require a write-down if the ceiling limit is exceeded.  Once a write-down is taken, it cannot be reversed in future periods even if natural gas and oil prices increase.

For the year ended December 31, 2012, we incurred a ceiling test write-down of $1,939.7 million which resulted in an operating loss for our company for 2012.  If natural gas and oil prices decline below levels utilized in our ceiling limit test as of December 31, 2012 and/or operating costs, development costs, transportation costs or basis differentials increase, a write-down may occur, which would adversely impact our results of operation and financial condition.  Using the first-day-of-the-month prices of natural gas for the first two months of 2013 and NYMEX strip prices for the remainder of 2013, as applicable, the prices required to be used to determine the ceiling limit could result in a ceiling test write-down in 2013.

Our level of indebtedness and the terms of our financing arrangements may adversely affect operations and limit our growth.

As of December 31, 2012, we had total indebtedness of $1,669.4 million, with no borrowings under our revolving credit facility.  At February 15, 2013, we had long-term indebtedness of $1,709.6 million, including borrowings of $40.2 million under our revolving credit facility.  We currently expect to utilize the borrowing availability under our revolving

credit facility in order to fund a portion of our capital investments in 2013.  See also our risk factor headed “We may have difficulty financing our planned capital investments which could adversely affect our growth,” below.

The terms of our various financing agreements, including but not limited to the indentures relating to our outstanding senior notes, our revolving credit facility and the master lease agreement relating to our drilling rigs and our other equipment leases, which we collectively refer to as our “financing agreements,” impose restrictions on our ability and, in some cases, the ability of our subsidiaries to take a number of actions that we may otherwise desire to take, including one or more of the following:

Our level of indebtedness and off-balance sheet obligations, and the covenants contained in our financing agreements, could have important consequences for our operations, including:

Our ability to comply with the covenants and other restrictions in our financing agreements may be affected by events beyond our control, including prevailing economic and financial conditions.  If we fail to comply with the covenants and other restrictions, it could lead to an event of default and the acceleration of our obligations under those agreements.  We may not have sufficient funds to make such payments.  If we are unable to satisfy our obligations with cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from a public offering of securities.  We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt, to meet our lease obligations, or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt or obligations.  The terms of our financing agreements may also prohibit us from taking such actions.  Factors that will affect our ability to raise cash through a public offering, a refinancing of our debt or a sale of assets include financial market conditions and our market value and operating performance at the time of such offering or other financing.  We cannot assure you that any such proposed offering, refinancing or sale of assets can be successfully completed or, if completed, that the terms will be favorable to us.

We may have difficulty financing our planned capital investments, which could adversely affect our growth.

We have experienced and expect to continue to experience substantial capital investment and working capital needs as a result of our drilling program. Our planned capital investments for 2013 are expected to exceed the net cash generated by our operations under current natural gas prices.  We expect to borrow under our revolving credit facility to fund capital investments that are in excess of our net cash flow and cash on hand.  Our ability to borrow under our revolving credit facility is subject to certain conditions.  As of December 31, 2012, we were in compliance with the borrowing conditions of our revolving credit facility.  If we are not in compliance with the terms of our revolving credit facility in the future or if the lenders under our revolving credit facility are unable to fulfill their commitments, we may not be able to borrow under the revolving credit facility to fund our capital investments.  We also cannot be certain that other financing will be available to us on acceptable terms or at all.  In the event additional capital resources are unavailable, we may curtail our drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.  Any such curtailment or sale could have a material adverse effect on our results and future operations.

Natural gas and oil prices are volatile.  Volatility in natural gas and oil prices can adversely affect our results and the price of our common stock.  This volatility also makes valuation of natural gas and oil producing properties difficult and can disrupt markets.

Natural gas and oil prices have historically been, and are likely to continue to be, volatile.  In recent years, there has been a significant decline in natural gas prices as evidenced by NYMEX natural gas prices ranging from a high of $13.58 per MMBtu in 2008 to a recent low of $1.91 per MMBtu in April 2012.  The prices for natural gas and oil are subject to

wide fluctuation in response to a number of factors, including:

Historically we have also experienced price volatility as a result of locational differentials for our production from the Arkoma Basin and East Texas, which at any time may further widen due to pipeline or other constraints. Price volatility makes it difficult to project the return on exploration and development projects involving our natural gas and oil properties and to estimate with precision the value of producing properties that we may own or propose to acquire.  In addition, unusually volatile prices often disrupt the market for natural gas and oil properties, as buyers and sellers have more difficulty agreeing on the purchase price of such properties.  Our results of operations may fluctuate significantly as a result of, among other things, variations in natural gas and oil prices and production performance.  In recent years, natural gas and oil price volatility has become increasingly severe. 

The recent adoption of financial reform legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business which could have a material adverse effect on our financial position, results of operations and cash flows.

In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act was passed by Congress and subsequently signed into law.  The new legislation required the Commodities Futures Trading Commission, or the CFTC, and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets.  The financial reform legislation may also require us to comply with margin requirements and with certain clearing and trade execution requirements in connection with our derivative activities.  At this time it is not possible to predict whether or when the CFTC will adopt those rules or include comparable provisions in its rulemaking under the new legislation or how those rules will apply to us. The financial reform legislation may also require the counterparties to our derivative instruments to spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties, and such developments may affect the business relationships we have with those counterparties. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks, reduce our ability to monetize or restructure our existing derivative contracts, increase our exposure to less creditworthy counterparties and limit our access to the capital necessary to grow our business. If, as a result of the legislation and regulations, we are no longer able to use derivatives as we have in the past, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital investments. Our revenues could also be adversely affected if a consequence of the legislation and regulations is lower commodity prices. Any of these consequences could have a material adverse effect on our financial position, results of operations and cash flows.

Working interest owners of some of our properties may be unwilling or unable to cover their portion of development costs, which could change our exploration and development plans.  

Some of our working interest owners may have difficulties obtaining the capital needed to finance their activities, or may believe that estimated drilling and completion costs are excessive. As a result, these working interest owners may choose not to participate in certain wells or be unable or unwilling to pay their share of well costs as they become due. These actions could cause us to change our development plans for the affected properties.

Although our estimated natural gas and oil reserve data is independently audited, our estimates may still prove to be inaccurate.

Our reserve data represents the estimates of our reservoir engineers made under the supervision of our management.  Our reserve estimates are audited each year by Netherland, Sewell & Associates, Inc., or NSAI, an independent petroleum engineering firm.  In conducting its audit, the engineers and geologists of NSAI study our major properties in detail and independently develop reserve estimates.  NSAI’s audit consists primarily of substantive testing, which includes a detailed review of major properties that account for approximately 93% of present worth of our total proved reserves.  NSAI’s audit process consists of sorting all fields by descending present value order and selecting the fields from highest value to descending value until the selected fields account for more than 80% of the present worth of our reserves.  The properties in the bottom 20% of the total present worth are not reviewed in the audit.  The fields included in approximately the top 93% present value as of December 31, 2012 accounted for approximately 95% of our total proved reserves and approximately 98% of our proved undeveloped reserves.  In the conduct of its audit, NSAI did not independently verify the data we provided to them with respect to ownership interests, oil and natural gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the properties and sales of production.  NSAI has advised us that if, in the course of its audit, something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved any questions relating thereto or had independently verified such information or data. On January 17, 2013, NSAI issued its audit opinion as to the reasonableness of our reserve estimates for the year ended December 31, 2012, stating that our estimated proved oil and natural gas reserves are, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.

Natural gas and oil reserves cannot be measured exactly.  Our estimate of natural gas and oil reserves requires extensive judgments of reservoir engineering data and projections of cost that will be incurred in developing and producing reserves and is generally less precise than other estimates made in connection with financial disclosures. Our reservoir engineers prepare our reserve estimates under the supervision of our management.  Reserve estimates are prepared for each of our properties annually by the reservoir engineers assigned to the asset management team to which the property is assigned.  The reservoir engineering and financial data included in these estimates are reviewed by senior engineers who are not part of the asset management teams and our Manager – Capital Budgeting & Reserves, who is the technical person primarily responsible for the preparation of our reserve estimates, and has over ten years of experience in petroleum engineering, including the estimation of oil and natural gas reserves.  He reports to our Senior Vice President – Corporate Development, who has more than 31 years of experience in reservoir engineering, including the estimation of oil and natural gas reserves in multiple basins, both in the United States and internationally.  On our behalf, the Senior Vice President – Corporate Development engages NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates as discussed in more detail below. The financial data included in the reserve estimates are also separately reviewed by our accounting staff. Following these reviews and the audit, the reserve estimates are submitted by our Senior Vice President – Corporate Development, to our Chief Executive Officer for his review and approval prior to the presentation to our Board of Directors.  NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests.  We incorporate many factors and assumptions into our estimates including:

Although we believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates, our actual reserves could vary considerably from estimated quantities of proved natural gas and oil reserves (in the aggregate and for a particular geographic location), production, revenues, taxes and development and operating expenditures.  In addition, our estimates of reserves may be subject to downward or upward revision based upon production history, results of future exploration and development, prevailing natural gas and oil prices, severance taxes, operating and development costs and other factors.  In 2012, our reserves were revised downward by 2,088.2 Bcfe, which was primarily an effect of the low natural gas price environment encountered during the 2012 year and was also a result of downward performance revisions.  In 2011, our reserves were revised upward by 33.7 Bcfe, primarily due to improved performance in our Marcellus Shale properties, partially offset by downward performance revisions in our East Texas, Arkoma and Fayetteville properties and downward price revisions due to a comparative price decrease in the average 2011 price from the average 2010 price.  In 2010, our reserves were revised upward by 309.6 Bcfe, primarily due to improved performance in our Fayetteville Shale properties and upward price revisions due to a comparative price increase in the average 2010 price from the average 2009 price, partially offset by downward performance revisions in our East Texas

properties.  Because we review our reserve projections for every property at the end of every year, any material change in a reserve estimate is included in subsequent reserve reports.

Finally, recovery of undeveloped reserves generally requires significant capital investments and successful drilling operations.  As of December 31, 2012, approximately 821 Bcfe of our estimated proved reserves were undeveloped.  Our reserve data assume that we can and will make these expenditures and conduct these operations successfully, which may not occur.  Please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Cautionary Statement about Forward-Looking Statements” in Item 7 of Part II of this Form 10-K for additional information regarding the uncertainty of reserve estimates.

If we fail to find or acquire additional reserves, our reserves and production will decline materially from their current levels.

The rate of production from natural gas and oil properties generally declines as reserves are depleted.  Unless we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as reserves are produced.  Future natural gas and oil production is, therefore, highly dependent upon our level of success in acquiring or finding additional reserves.

Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change.

As of December 31, 2012, we had drilled and completed 2,874 operated wells relating to our Fayetteville Shale play and 76 operated wells relating to our Marcellus Shale play.  At year-end 2012, after the exclusion of our acreage in the traditional Fairway and the approximately 153,000 net federal acres we hold in the Ozark Highlands Unit, approximately 80% of our leasehold acreage in the Fayetteville Shale was held by production.  Approximately 10% of our leasehold acreage in the Marcellus Shale was held by production at year-end 2012. Our drilling plans are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful wells in addition to the natural gas and oil commodity price environment.  The determination as to whether we continue to drill wells in our operating areas may depend on any one or more of the following factors:

We continue to gather data about our prospects in our operating areas, and it is possible that additional information may cause us to alter our drilling schedule or determine that prospects in some portion of our acreage position should not be pursued at all.

If we fail to drill all of the wells that are necessary to hold our acreage, the initial lease terms could expire, which would result in the loss of certain leasehold rights.

Leases on approximately 268,902 net acres of our Fayetteville Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases, of which 153,863 net acres are held on federal lands.  Approximately 59,162 net acres of our Marcellus Shale acreage will expire in the next three years if we do not drill successful wells to develop the acreage or otherwise take action to extend the leases.  As

discussed above under “Our drilling plans for the Fayetteville Shale play and Marcellus Shale play are subject to change,” our ability to drill wells depends on a number of factors, including certain factors that are beyond our control.  With the exception of the Ozark Highlands Unit, which is federally leased, the current rules in Arkansas relating to the Fayetteville Shale provide that each drilling unit would consist of a governmental section of approximately 640 acres and operators are permitted to drill up to 16 wells per drilling unit for each unconventional source of supply.  In Pennsylvania, the location of our Marcellus Shale acreage, there are currently no rules establishing requirements for drilling units.  However, current rules in Arkansas may change and rules may be implemented in Pennsylvania that could impair our ability to drill or maintain our acreage position.  In addition, other E&P operator drilling activity could impair our ability to drill and maintain acreage positions.  To the extent that any field rules prevent us from successfully drilling wells in certain areas, we may not be able to drill the wells required to maintain our leasehold rights and our leasehold investments could be lost.

If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce our projected supply of natural gas, our investments in our gas gathering operations could be lost.  In addition, our commitments for transportation on third-party pipelines and gathering systems could make the sale of our natural gas uneconomic, which could have an adverse effect on our results of operations, financial condition and cash flows.

Through December 31, 2012, we had invested approximately $1,038 million in our gas gathering system built for the Fayetteville Shale play and approximately $203 million in our gas gathering system built for the Marcellus Shale play.  To the extent necessary to gather our production, we may make further substantial investments in the expansion of our gas gathering systems.  Our gas gathering business will largely rely on natural gas sourced from our operations.  Our marketing subsidiary has also entered into multiple firm transportation agreements relating to natural gas volumes produced from our Fayetteville Shale play as well as a number of firm transportation and gathering agreements relating to the Marcellus Shale play. As of December 31, 2012, our aggregate demand charge commitments under these firm transportation agreements and gathering agreements were approximately $2.8 billion. If our Fayetteville Shale and Marcellus Shale drilling programs fail to produce significant supplies of natural gas, our investments in our gas gathering operations could be lost, and we could be forced to pay demand or other charges for transportation on pipelines and gathering systems that we would not be using.  These events could have an adverse effect on our results of operations, financial condition and cash flows.

Our exploration, development and drilling efforts and our operation of our wells may not be profitable or achieve our targeted returns.

Exploration, development, drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered.  We invest in property, including undeveloped leasehold acreage that we believe will result in projects that will add value over time. However, we cannot assure you that all prospects will result in viable projects or that we will not abandon our initial investments. Additionally, there can be no assurance that leasehold acreage acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells.  Drilling for natural gas and oil may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient net reserves to return a profit after deducting drilling, operating and other costs.  In addition, wells that are profitable may not achieve our targeted rate of return.  Our ability to achieve our target PVI results is dependent upon the current and future market prices for natural gas and oil, costs associated with producing natural gas and oil and our ability to add reserves at an acceptable cost.  We rely to a significant extent on seismic data and other advanced technologies in identifying leasehold acreage prospects and in conducting our exploration activities.  The seismic data and other technologies we use do not allow us to know conclusively prior to acquisition of leasehold acreage or drilling a well whether natural gas or oil is present or may be produced economically.  The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies.

In addition, we may not be successful in implementing our business strategy of controlling and reducing our drilling and production costs in order to improve our overall return.  The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.  Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures or accidents, adverse weather conditions, environmental and other governmental requirements and the cost of, or shortages or delays in the availability of, drilling rigs, equipment and services.

The success of our New Ventures projects is subject to drilling and completion technique risks and enhanced recovery methods.  Our drilling results may not meet our expectations for reserves or production and the value of our undeveloped New Venture acreage could decline.

Many of our operations involve utilizing the latest drilling and completion techniques as developed by ourselves and our service providers in order to maximize cumulative recoveries and therefore generate the highest possible returns. Risks that we face while drilling include, but are not limited to, landing our wellbore in the desired drilling zone, staying in the desired drilling zone while drilling horizontally through the formation, running our casing the entire length of the wellbore, and being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, being able to fracture stimulate the planned number of stages, being able to run tools the entire length of the wellbore during completion operations, and successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

We may inject water into formations on some of our properties to increase the production of oil, natural gas and associated liquids or employ other enhanced recovery methods in our operations. The additional production and reserves, if any, attributable to the use of enhanced recovery methods are inherently difficult to predict. If our enhanced recovery methods do not allow for the extraction of oil, natural gas and associated liquids in a manner or to the extent that we anticipate, we may not realize an acceptable return on our investments in such projects. In addition, if proposed legislation and regulatory initiatives relating to hydraulic fracturing become law, the cost of some of these enhanced recovery methods could increase substantially.

Ultimately, the success of drilling and completion techniques and enhanced recovery methods can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, limited access to gathering systems and takeaway capacity, and/or oil, natural gas and NGL prices decline, the return on our investment for a particular project may not be as attractive as we anticipated and the value of our undeveloped acreage could decline in the future.

Our financial condition and results of operation could be adversely affected by legislative and regulatory initiatives in the United States and Canada relating to hydraulic fracturing that could result in increased costs and additional operating restrictions or delays or prevent us from realizing the value of undeveloped acreage.

We utilize hydraulic fracturing in our E&P operations as a means of maximizing the productivity of our wells.  It is an essential and common practice in the oil and gas industry used to stimulate production of oil, natural gas, and associated liquids from dense subsurface rock formations. The knowledge and expertise in fracturing techniques we have developed through our operations in the Fayetteville Shale play are being utilized in our other operating areas, currently including our Marcellus Shale acreage and in the future expected to also include our exploration program in New Brunswick, Canada. Successful hydraulic fracturing techniques are also expected to be critical to the development of our recently announced unconventional horizontal oil play targeting the LSBD formation in Arkansas and Louisiana.  Hydraulic fracturing involves using water, sand, and certain chemicals to fracture the hydrocarbon-bearing rock formation to allow the flow of hydrocarbons into the wellbore. In our Fayetteville Shale and Marcellus Shale plays, the fracturing fluids we use are comprised of over 99.9% water and sand.  The remaining 0.1% is comprised of small quantities of additives which contain chemical compounds such as hydrochloric acid, phosphoric acid, glutaraldehyde and sodium chloride which is used in common household products.

In the past few years, there has been an increased focus on environmental aspects of hydraulic fracturing practices in the United States and Canada.  In the United States, hydraulic fracturing is typically regulated by state oil and natural gas commissions but there has recently been a number of regulatory initiatives at the federal and local levels as well as by other state agencies.    The EPA has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act and has begun the process of drafting guidance documents related to this newly asserted regulatory authority.

In addition, the EPA issued final rules effective as of October 15, 2012 that subject oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the NSPS and NESHAPS programs. The EPA final rules also include NSPS standards for completions of hydraulically fractured gas wells. These standards include the REC techniques developed in the EPA's Natural Gas STAR program. The standards would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the final regulations under NESHAPS include MACT standards for those glycol dehydrators and storage vessels at major sources of hazardous air pollutants not currently subject to MACT standards. Based on our current operations and practices, management believes, such newly promulgated rules

will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future.

In October 2011, the EPA also announced a schedule for development of standards for disposal of wastewater produced from shale gas operations to POTWs. The regulations will be developed under the EPA's Effluent Guidelines Program under the authority of the Clean Water Act. The EPA anticipates issuing the proposed rules in 2014.

In addition to the EPA’s efforts, legislation has been introduced before Congress, called the Fracturing Responsibility and Awareness of Chemicals Act, to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process. There are also certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. A number of federal agencies are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and while initial results were expected to be available by late 2012 and final results by 2014, to date the EPA has not released any results from the study. In addition, the U.S. Department of Energy is conducting an investigation into practices the agency could recommend to better protect the environment from drilling using hydraulic fracturing completion methods. Also, the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal lands.

Certain states in which we operate have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure, waste disposal and well construction requirements on hydraulic fracturing operations or otherwise seek to ban fracturing activities altogether.  In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general and/or hydraulic fracturing in particular. In the event state, local, or municipal legal restrictions are adopted in areas where we are currently conducting, or in the future plan to conduct operations, we may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from the drilling and/or completion of wells.

In the Province of New Brunswick in Canada there are presently no hydraulic fracturing regulations, however the provincial government has been working on a new comprehensive regulatory framework that is expected to be released to the public in late 2013.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil, natural gas, and associated liquids including from the development of shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of additional federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells, increased compliance costs and time, which could adversely affect our financial position, results of operations and cash flows.

We incur substantial costs to comply with government regulations, especially regulations relating to environmental protection, and could incur even greater costs in the future.

Our exploration, production, development and gas gathering and marketing operations are regulated extensively at the federal, state and local levels.  We have made and will continue to make large expenditures in our efforts to comply with these regulations, including environmental regulation. The natural gas and oil regulatory environment could change in ways that might substantially increase these costs.  Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights.  These regulations affect our operations and limit the quantity of hydrocarbons we may produce and sell.  In addition, at the U.S. federal level, the FERC regulates interstate transportation of natural gas under the NGA.  Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

As an owner or lessee and operator of natural gas and oil properties, an owner of gas gathering systems, a sand mine and provider of pressure pumping services, we are subject to various federal, state and local regulations relating to discharge of materials into, and protection of, the environment.  These regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from operations, subject us to liability for pollution damages, and require suspension or cessation of operations in affected areas.  Changes in or additions to regulations regarding the protection of the environment could significantly increase our costs of compliance, or otherwise adversely affect our business.

One of the responsibilities of owning and operating natural gas and oil properties is paying for the cost of abandonment. We may incur significant abandonment costs in the future which could adversely affect our financial results.

Natural gas and oil drilling and producing operations involve various operating and environmental risks that could result in substantial losses.

Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties, the drilling of natural gas and oil wells and the sale of natural gas and oil, including but not limited to encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, hydrocarbon drainage from adjacent third-party production, release of contaminants into the environment and other environmental hazards and risks and failure of counterparties to perform as agreed.

We maintain insurance against many potential losses or liabilities arising from our operations in accordance with customary industry practices and in amounts that we believe to be prudent.  However, our insurance does not protect us against all operational risks.  For example, we generally do not maintain business interruption insurance.  Additionally, pollution and environmental risks generally are not fully insurable.  These risks could give rise to significant costs not covered by insurance that could have a material adverse effect upon our financial results. 

Our ability to sell our natural gas and oil and/or to receive market prices for our production may be adversely affected by constraints or interruptions on gathering systems, pipelines, processing and transportation systems owned or operated by us or others. 

The marketability of our natural gas and oil production depends in part on the availability, proximity, and capacity of gathering systems, processing and pipeline and other transportation systems owned or operated by third parties. The lack of available capacity in these systems and facilities can result in the shutting-in of producing wells, the delay or discontinuance of development plans for our properties, or lower price realizations. Although we have some contractual control over the transportation and gathering of our production, material changes in these business relationships could materially affect our operations. Federal and state regulation of natural gas and oil production, processing and transportation, tax and energy policies, changes in supply and demand, pipeline pressures, damage to or destruction of pipelines, infrastructure or capacity constraints, and general economic conditions could adversely affect our ability to produce, gather, and transport natural gas.

 In particular, if drilling in the Marcellus Shale play continues to be successful, the amount of natural gas being produced by us and others could exceed the capacity of, and result in strains on, the various gathering, and transportation systems, pipelines, and other infrastructure available in these areas. It will be necessary for additional infrastructure, pipelines, gathering, and transportation systems and processing facilities to be expanded, built or developed to accommodate anticipated production from these areas. Because of the current economic climate, certain processing or pipeline and other gathering or transportation projects that might be, or are being, considered for these areas may not be developed timely or at all due to lack of financing, construction and permitting delays, permitting costs, well fees proposed in Pennsylvania, or other constraints. In addition, capital and other constraints could limit our ability to build or access intrastate gathering and transportation systems necessary to transport our production to interstate pipelines or other points of sale or delivery. In such event, we might have to delay or discontinue development activities or shut in our wells to wait for sufficient infrastructure development or capacity expansion and/or sell production at significantly lower prices than those quoted on NYMEX, which would adversely affect our results of operations and cash flows.

A portion of our production in any region may be interrupted, or shut in, from time to time for numerous reasons, including as a result of weather conditions, accidents, loss of pipeline, gathering, processing or transportation system access or capacity, field labor issues or strikes, or we might voluntarily curtail production in response to market conditions. If a substantial amount of our production is interrupted at the same time, it could temporarily adversely affect our cash flows and results of operations.

Shortages of oilfield equipment, services, supplies, raw materials and qualified personnel could adversely affect our results of operations. 

The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the natural gas and oil industry can fluctuate significantly, often in correlation with natural gas and oil prices, causing periodic shortages. These factors also cause significant increases in costs for equipment, services, personnel and raw materials (such as sand, cement, manufactured proppants and other materials utilized in the provision of the oilfield services).  Higher natural gas and oil prices generally stimulate increased

demand and result in increased prices for drilling rigs, crews and associated supplies, equipment, services and raw materials.  In addition, our E&P operations also require local access to large quantities of water supplies and disposal services for produced water in connection with our hydraulic fracture stimulations due to prohibitive transportation costs. We cannot be certain when we will experience shortages or price increases, which could adversely affect our profit margin, cash flow and operating results or restrict our ability to drill wells and conduct ordinary operations.

Our business could be adversely affected by competition with other companies.    

The natural gas and oil industry is highly competitive, and our business could be adversely affected by companies that are in a better competitive position.  As an independent natural gas and oil company, we frequently compete for reserve acquisitions, exploration leases, licenses, concessions, marketing agreements, equipment and labor against companies with financial and other resources substantially larger than those we possess.  Many of our competitors may be able to pay more for exploratory prospects and productive natural gas and oil properties and may be able to define, evaluate, bid for and purchase a greater number of properties and prospects than we can.  Our ability to explore for natural gas and oil prospects and to acquire additional properties in the future will depend on our ability to conduct operations, to evaluate and select suitable properties and to consummate transactions in this highly competitive environment.  In addition, many of our competitors have been operating in some of our core areas for a much longer time than we have or have established strategic long-term positions in geographic regions in which we may seek new entry.

We have made significant investments in our oilfield service operations, including our drilling rig, pressure pumping equipment and sand mine operations in order to meet certain of our oilfield service and resource needs, lower our costs and increase of the efficiency of our operations.  If our exploration and production activities are curtailed or disrupted, these operations may adversely impact our results of operations.  In addition, our continued expansion of these operations may adversely impact our relationships with third-party providers. 

We have made significant investments in order to meet certain of our oilfield services needs, including establishing our own drilling rig operations and sand mine.  In 2012, we invested in and commenced providing pressure pumping services for a portion of our operated wells.  We may make additional investments to expand these operations in the future.  Our drilling operations are conducted through our subsidiary, DeSoto Drilling, Inc., which had 371 employees as of December 31, 2012.  We have lease commitments for 14 drilling rigs and related equipment with respect to DDI's operations and we also own one drilling rig.  In addition to these rigs, we have contracts with third-party drilling companies for use of their rigs which may not be terminable without penalty.  In 2009, another of our subsidiaries, DeSoto Sand, L.L.C., began operating our first sand mine in Arkansas in order to meet a portion of our sand needs for the Fayetteville Shale play. We also purchase sand for use in our operations from various third parties, including certain of our oilfield service providers.  Our drilling rig and sand mine operations may have an adverse effect on our relationships with our existing third-party service and resource providers or our ability to secure these services and resources from other providers.  We may also compete with third-party providers for qualified personnel, which could adversely affect our relationships with such providers. If the operations of our drilling rigs and/or sand mine are disrupted or our existing third-party providers discontinue their relationships with us, we may not be able to secure alternative services or resources on a timely basis, or at all.  Even if we are able to secure alternative services or resources, there can be no assurance that such services or resources will be of equivalent quality or that pricing and other terms will be favorable to us.  If we are unable to secure third-party services or resources or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

We depend upon our management team and our operations require us to attract and retain experienced technical personnel.    

The successful implementation of our business strategy and handling of other issues integral to the fulfillment of our business strategy depends, in part, on our experienced management team, as well as certain key geoscientists, geologists, engineers and other professionals employed by us.  The success of our technological initiatives that support our business enterprise is also dependent upon attracting and retaining experienced technical professionals.  The loss of key members of our management team or other highly qualified technical professionals could have a material adverse effect on our business, financial condition and operating results.

If natural gas prices decline further, our failure to hedge the remaining portion of our expected 2013 production could adversely affect our results of operations and financial condition.

To reduce our exposure to fluctuations in the prices of natural gas and oil, historically, we have entered into hedging arrangements with respect to a significant portion of our expected production.  As of February 15, 2013, we had NYMEX commodity price hedges on approximately 29% of our targeted 2013 natural gas production as compared to approximately

30% for 2010, 52% for 2011 and 47% for 2012.  Our price risk management activities increased natural gas sales by $617.6 million in 2012, increased natural gas sales by $315.6 million in 2011 and increased natural gas sales by $290.3  million in 2010. If natural gas prices decline in 2013, unless we enter into additional hedging arrangements, our revenues would be adversely affected.   To the extent that we engage in additional hedging activities in the current price environment, we would not realize the benefit of price increases above the levels of the hedges. 

In addition, such transactions may expose us to the risk of financial loss in certain circumstances, including instances in which:

Finally, future market price volatility could create significant changes to the hedge positions recorded on our financial statements.  We refer you to “Quantitative and Qualitative Disclosures about Market Risk” in Item 7A of Part II of this Form 10-K.

Certain U.S. federal income tax deductions currently available with respect to oil and natural gas exploration and production may be eliminated as a result of future legislation.

The elimination of certain key U.S. federal income tax deductions currently available to oil and natural gas exploration and production companies has been proposed in recent years. These changes have included, among other proposals:

It is unclear whether these or similar changes will be enacted. The passage of these or any similar changes in federal income tax laws to eliminate or postpone certain tax deductions that are currently available with respect to oil and natural gas exploration and development could have an adverse effect on our financial position, results of operations and cash flows.

Our ability to produce natural gas could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of the water we use at a reasonable cost and within applicable environmental rules.

Our inability to locate sufficient amounts of water, or dispose of or recycle water used in our E&P operations, could adversely impact our operations, particularly with respect to our Fayetteville Shale and Marcellus Shale operations, and also possibly our recently announced unconventional oil play targeting the LSBD formation in Arkansas and Louisiana. Moreover, the imposition of new environmental initiatives and regulations could include restrictions on our ability to conduct certain operations such as hydraulic fracturing or disposal of waste, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of natural gas.  The Federal Water Pollution Control Act, as amended, or the FWPCA, imposes restrictions and strict controls regarding the discharge of produced waters and other natural gas and oil waste into navigable waters.  Permits must be obtained to discharge pollutants to waters and to conduct construction activities in waters and wetlands.  The FWPCA and similar state laws provide for civil, criminal and administrative penalties for any unauthorized discharges of pollutants and unauthorized discharges of reportable quantities of oil and other hazardous substances. Many state discharge regulations and the Federal National Pollutant Discharge Elimination System general permits issued by the EPA prohibit the discharge of produced water and sand, drilling fluids, drill cuttings and certain other substances related to the natural gas and oil industry into coastal waters. The EPA has also adopted regulations requiring certain natural gas and oil exploration and production facilities to obtain permits for storm water discharges. Compliance with environmental regulations and permit requirements governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted, all of which could have an adverse  effect on our operations and financial condition.

Climate change and global warming concerns could lead to additional regulatory measures that may adversely impact our operations and financial condition.

Our E&P operations are currently focused on the production of hydrocarbons from unconventional sources, and we expect to continue to focus on such resources in the future. The production of hydrocarbons from these sources has an energy intensity that is a number of times higher than that for production from conventional sources. Therefore, we expect that the carbon dioxide, or CO2, intensity of our production will increase in the long-term. We actively seek to reduce the environmental impact of our operations by pursuing more efficient use of natural resources such as hydrocarbons and water and managing and mitigating the emissions to the air, water and soil, with a focus on the reduction of greenhouse gas emissions. With the efforts of our Health, Safety and Environmental Department, we have been able to plan for and comply with environmental initiatives without materially altering our operating strategy. We anticipate making increased expenditures of both a capital and expense nature as a result of the increasingly stringent laws relating to the protection of the environment that will increase the cost of equipment, materials and services whose production utilizes hydrocarbons. We may also face increased competition from alternative energy sources that do not rely on hydrocarbons. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters and if we are unable to find solutions to environmental initiatives as they arise, including reducing the CO2 emissions for our existing projects, we may have additional costs as well as compliance and operational risks with respect to our existing operations as well as facing difficulties in pursuing new projects.

Our certificate of incorporation and, bylaws contain provisions that could make it more difficult for someone to either acquire us or affect a change of control.

Certain provisions of our certificate of incorporation and bylaws, together with any stockholder rights plan that we might have in place, could discourage an effort to acquire us, gain control of the company, or replace members of our executive management team. These provisions could potentially deprive our stockholders of opportunities to sell shares of our common stock at above-market prices.

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 2.  PROPERTIES

The summary of our oil and natural gas reserves as of fiscal year-end 2012 based on average fiscal-year prices, as required by Item 1202 of Regulation S-K, is included in the table headed “2012 Proved Reserves by Category and Summary Operating Data” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K and incorporated by reference into this Item 2.  Our proved reserves are based upon estimates prepared for each of our properties annually by the reservoir engineers assigned to the asset management team in the geographic locations in which the property is located. These estimates are reviewed by senior engineers who are not part of the asset management teams and by our Manager – Capital Budgeting & Reserves, who is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Manager – Capital Budgeting & Reserves has more than ten years of experience in petroleum engineering, including the estimation of oil and natural gas reserves, and holds a Bachelor of Science in Petroleum Engineering. Prior to joining us in 2009, our Manager – Capital Budgeting & Reserves served in various reservoir engineering roles for Kinder Morgan CO2 and Citation Oil & Gas and is a member of the Society of Petroleum Engineers. He reports to our Senior Vice President – Corporate Development who has more than 31 years of experience in reservoir engineering including the estimation of oil and natural gas reserves in multiple basins both in the United States and internationally. Prior to joining Southwestern in 2008, our Senior Vice President – Corporate Development served in various engineering and senior management roles for Tenneco Oil Company, Enron Oil & Gas Company, Enron Global Exploration & Production, El Paso Energy and The Houston Exploration Company, and is a member of the Society of Petroleum Engineers, IPAA, Tipro and the Houston Producer’s Forum. On our behalf, the Senior Vice President – Corporate Development engages Netherland, Sewell & Associates, Inc., or NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies, to independently audit our proved reserves estimates. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-002699. Within NSAI, the two technical persons primarily responsible for auditing our proved reserves estimates (1) have over 26 years and over 11 years of practical experience in petroleum geosciences and petroleum engineering, respectively; (2) have over 22 years and over 11 years of experience in the estimation and evaluation of reserves, respectively; (3) each has a college degree; (4) each is a Licensed Professional Geoscientist in the State of Texas or a Licensed Professional Engineer in the State of Texas; (5) each meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; and (6) each is proficient in judiciously

applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines. The financial data included in the reserve estimates are also separately reviewed by our accounting staff. Our proved reserves estimates, as internally reviewed and audited by NSAI, are submitted for review and approval to our Chief Executive Officer.  Finally, upon his approval, NSAI reports the results of its reserve audit to the Board of Directors with whom final authority over the estimates of our proved reserves rests.  A copy of NSAI's report has been filed as Exhibit 99.1 to this Form 10-K. 

The information regarding our proved undeveloped reserves required by Item 1203 of Regulation S-K is included under the heading “Proved Undeveloped Reserves” in “Business – Exploration and Production – Our Proved Reserves” in Item 1 of this Form 10-K.

The information regarding delivery commitments required by Item 1207 of Regulation S-K is included under the heading “Sales, Delivery Commitments and Customers” in the “Business – Exploration and Production – Our Operations” in Item 1 of this Form 10-K and incorporated by reference into this Item 2. For additional information about our natural gas and oil operations, we refer you to Note 4 to the consolidated financial statements.  For information concerning capital investments, we refer you to “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Capital Investments.”  We also refer you to Item 6, “Selected Financial Data” in Part II of this Form 10-K for information concerning natural gas and oil produced.

The information regarding oil and gas properties, wells, operations and acreage required by Item 1208 of Regulation S-K is set forth below:

Leasehold acreage as of December 31, 2012:  

(1)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 46,007 net acres in 2013, 183,824 net acres in 2014, which includes 153,863 net acres held on federal lands, and 39,071 net acres in 2015.

(2)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 41,860 net acres in 2013, 13,467 net acres in 2014 and 3,835 net acres in 2015. 

(3)Includes 123,442 net developed acres and 1,211 net undeveloped acres in the Arkoma Basin that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.  Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,200 net acres in 2013, 670 net acres in 2014 and 17,788 net acres in 2015.

(4)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,340 net acres in 2013, 152 net acres in 2014 and 202 net acres in 2015. 

(5)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 68,023 net acres in 2013, 237,181 net acres in 2014 and 159,718 net acres in 2015.

(6)Assuming successful wells are not drilled to develop the acreage and leases are not extended, leasehold expiring over the next three years will be 1,120 net acres in 2013, 60,294 net acres in 2014 and 142,294 net acres in 2015.

(7)Assuming successful wells are not drilled to develop the acreage and our exploration license agreements are not extended, 2,518,518 net acres in New Brunswick will expire in March 2015. We have applied for an additional 1-year option to extend our exploration license agreements in New Brunswick and, if granted by the Province, this would extend our exploration license agreements until March 2016.

Producing wells as of December 31, 2012:  

(1)As of December 31, 2012, this includes 58 gross natural gas wells in which we own an overriding royalty interest.

(2)  As of December 31, 2012, this includes 148 gross natural gas wells in which we own an overriding royalty interest.

(3)  As of December 31, 2012, this includes 1 gross oil well and 12 gross natural gas wells in which we own an overriding royalty interest.

The information regarding drilling and other exploratory and development activities required by Item 1205 of Regulation S-K is set forth below:

(1)We have not drilled any exploratory or development wells in Canada in the past three years.

(2)2012 dry wells include 5 gross wells that were use for science in the Ozark Highlands Unit that were not intended to produce.

(3)  2010 dry wells include 2 gross wells (1.6 net wells) in the Fayetteville Shale play that were plugged and abandoned due to mechanical issues encountered during drilling.

The following table presents the information regarding our present activities required by Item 1206 of Regulation S-K:

Wells in progress as of December 31, 2012:  ⁽¹⁾

(1)As of December 31, 2012, we did not have any drilling activities in Canada.

The information regarding oil and gas production, production prices and production costs required by Item 1204 of Regulation S-K is set forth below:

Production, Average Sales Price and Average Production Cost:

(1)Our Fayetteville Shale and Marcellus Shale operations did not produce any oil for the years ended December 31, 2012, 2011 and 2010.

During 2012, we were required to file Form 23, “Annual Survey of Domestic Oil and Gas Reserves,” with the U.S. Department of Energy.  The basis for reporting reserves on Form 23 is not comparable to the reserve data included in Note 4 to the consolidated financial statements in Item 8 to this Form 10-K. The primary differences are that Form 23 reports gross reserves, including the royalty owners’ share, and includes reserves for only those properties of which we are the operator.

Miles of Pipe

As of December 31, 2012, our Midstream Services segment had 1,852 miles, 57 miles and 25 miles of pipe in its gathering systems located in Arkansas, Pennsylvania, and Texas, respectively.

Title to Properties

We believe that we have satisfactory title to substantially all of our active properties in accordance with standards generally accepted in the oil and gas industry.  Our properties are subject to customary royalty and overriding royalty interests, certain contracts relating to the exploration, development, operation and marketing of production from such properties, consents to assignment and preferential purchase rights, liens for current taxes, applicable laws and other burdens, encumbrances and irregularities in title, which we believe do not materially interfere with the use of or affect the value of such properties.  Prior to acquiring undeveloped properties, we endeavor to perform a title investigation that is thorough but less vigorous than that we endeavor to conduct prior to drilling, which is consistent with standard practice in the oil and natural gas industry.  Generally, before we commence drilling operations on properties that we operate, we endeavor to conduct a thorough title examination and perform curative work with respect to significant defects before proceeding with operations.  We believe that we have performed a thorough title examination with respect to substantially all of our active properties that we operate.

ITEM 3.  LEGAL PROCEEDINGS 

Tovah Energy

In February 2009, SEPCO was added as a defendant in a Third Amended Petition in the matter of Tovah Energy, LLC and Toby Berry-Helfand v. David Michael Grimes, et, al.  In the Sixth Amended Petition, filed in July 2010, in the 273rd District Court in Shelby County, Texas (collectively, the “Sixth Petition”), plaintiff alleged that, in 2005, they provided SEPCO with proprietary data regarding two prospects in the James Lime formation pursuant to a confidentiality agreement and that SEPCO refused to return the proprietary data to the plaintiff, subsequently acquired leases based upon such proprietary data and profited therefrom.  Among other things, the plaintiff’s allegations in the Sixth Petition included various statutory and common law claims, including, but not limited to claims of misappropriation of trade secrets, violation of the Texas Theft Liability Act, breach of fiduciary duty and confidential relationships, various fraud based claims and breach of contract, including a claim of breach of a purported right of first refusal on all interests acquired by SEPCO between February 15, 2005 and February 15, 2006.  In the Sixth Petition, plaintiff sought actual damages of over $55.0 million as well as other remedies, including special damages and punitive damages of four times the amount of actual damages established at trial.

Immediately before the commencement of the trial in November 2010, plaintiff was permitted, over SEPCO’s objections, to file a Seventh Amended Petition claiming actual damages of $46.0 million and also seeking the equitable remedy of disgorgement of all profits for the misappropriation of trade secrets and the breach of fiduciary duty claims. In December 2010, the jury found in favor of the plaintiff with respect to all of the statutory and common law claims and awarded $11.4 million in compensatory damages. The jury did not, however, award the plaintiff any special, punitive or other damages. In addition, the jury separately determined that SEPCO’s profits for purposes of disgorgement were $381.5 million. This profit determination does not constitute a judgment or an award. The plaintiff’s entitlement to disgorgement of profits as an equitable remedy will be determined by the judge and it is within the judge’s discretion to award none, some or all the amount of profit to the plaintiff.  On December 31, 2010, the plaintiff filed a motion to enter the judgment based on the jury’s verdict.  On February 11, 2011, SEPCO filed a motion for a judgment notwithstanding the verdict and a motion to disregard certain findings.  On March 11, 2011, the plaintiff filed an amended motion for judgment and intervenor filed its motion for judgment seeking not only the monetary damages and the profits determined by the jury but also seeking, as a new remedy, a constructive trust for profits from 143 wells as well as future drilling and sales of properties in the prospect areas.  A hearing on the post-verdict motions was held on March 14, 2011.  At the suggestion of the judge, all parties voluntarily agreed to participate in non-binding mediation efforts.  The mediation occurred on April 6, 2011 and was unsuccessful. On June 6, 2011, SEPCO received by mail a letter dated June 2, 2011 from the judge, in which he made certain rulings with respect to the post-verdict motions and responses filed by the parties. In his rulings, the judge denied SEPCO’s motion for judgment, judgment notwithstanding the verdict and to disregard certain findings. Plaintiff’s and intervenor’s claim for a constructive trust was denied but the judge ruled that plaintiff and intervenor shall recover from SEPCO $11.4 million and a reasonable attorney’s fee of 40% of the total damages awarded and are entitled to recover on their claim for disgorgement.  The judge instructed that SEPCO calculate the profit on the designated wells for each respective period.  SEPCO performed the calculation and provided it to the judge in June 2011.  On July 5, 2011, plaintiff and intervenor filed a letter with the court raising objections to the accounting provided by SEPCO, to which SEPCO filed a response on July 11, 2011.  On July 12, 2011, the judge sent a letter to the parties in which he ruled that after reviewing the parties’ respective position letters, he was awarding $23.9 million in disgorgement damages in favor of the plaintiff and intervenor.  In the July 12, 2011 letter, the judge instructed the plaintiff and intervenor to prepare a judgment for his approval prior to July 21, 2011 consistent with his findings in his June 2, 2011 letter and the disgorgement award.  On August 24, 2011, a judgment was entered pursuant to which plaintiff and intervenor are entitled to recover approximately $11.4 million in actual damages and approximately $23.9 million in disgorgement as well as prejudgment interest and attorneys' fees which currently are estimated to be up to $8.9 million and all costs of court of the plaintiff and intervenor.  On September 23, 2011, SEPCO filed a motion for a new trial and on November 18, 2011 filed a notice of appeal.  On November 30, 2011, the court approved SEPCO’s supersedeas bond in the amount of $14.1 million, which stays execution on the judgment pending appeal.  The bond covers the $11.4 million judgment for actual damages, plus $1.3 million in pre-judgment interest, $1.3 million in post-judgment interest (estimating two years for the duration of appeal), and court costs. 

On June 22, 2012, SEPCO filed its appellate brief and, on June 25, 2012, plaintiff and intervenor filed a cross-appellate brief seeking limited remand to reassess the disgorgement determination.  The parties filed their responses to the appellate and cross-appellate briefs on or about November 7, 2012.  Both sides filed replies to the opposing party’s responses in January 2013.  Oral arguments are expected to occur in spring 2013.  Based on the Company's understanding and judgment of the facts and merits of this case, including appellate defenses, and after considering the advice of counsel, the Company has determined that, although reasonably possible after exhaustion of all appeals, an adverse final outcome to this lawsuit is not probable.  As such, the Company has not accrued any amounts with respect to this lawsuit.  If the plaintiff and intervenor were to ultimately prevail in the appellate process, the Company currently estimates, based on the judgments to date, that SEPCO’s potential liability would be up to $44.2 million, including interest and attorney’s fees. The Company’s assessment may change in the future due to occurrence of certain events, such as denied appeals, and such re-assessment could lead to the determination that the potential liability is probable and could be material to the Company's results of operations, financial position or cash flows.

Muncey

On February 20, 2012, the Company became aware that SEPCO was named as a defendant in the matter of Gery Muncey v. Southwestern Energy Production Company, et al filed in the District Court of San Augustine County in Texas on January 31, 2012.  The plaintiff in this case is also the intervenor in the Tovah Energy matter described above and alleged various claims including fraud, misappropriation and breach of fiduciary duty that are purportedly independent of the claims alleged in the Tovah Energy matter but arise from the substantially same circumstances involved in the Tovah Energy matter.  SEPCO’s motion for summary judgment was granted on July 9, 2012. On August 22, 2012, the court signed a final take-nothing judgment in SEPCO’s favor.  The deadlines for filing appeals have expired, so this matter has been resolved in SEPCO’s favor.

Bureau of Land Management

In March 2010, the Company’s subsidiary, SEECO, was served with a subpoena from a federal grand jury in Little Rock, Arkansas.  Based on the documents requested under the subpoena and subsequent discussions described below, the Company believes the grand jury is investigating matters involving approximately 27 horizontal wells operated by SEECO in Arkansas, including whether appropriate leases or permits were obtained therefor and whether royalties and other production attributable to federal lands have been properly accounted for and paid.  The Company believes it has fully complied with all requests related to the federal subpoena and delivered its affidavit to that effect. The Company and representatives of the Bureau of Land Management and the U.S. Attorney have had discussions since the production of the documents pursuant to the subpoena.  In January 2011, the Company voluntarily produced additional materials informally requested by the government arising from these discussions.  Although, to the Company’s knowledge, no proceeding in this matter has been initiated against SEECO, the Company cannot predict whether or when one might be initiated. The Company intends to fully comply with any further requests and to cooperate with any related investigation. No assurance can be made as to the time or resources that will need to be devoted to this inquiry or the impact of the final outcome of the discussions or any related proceeding. 

Other

We are subject to various litigation, claims and proceedings that have arisen in the ordinary course of business. Management believes, individually or in aggregate, such litigation, claims and proceedings will not have a material adverse impact on our financial position, results of operations or cash flows but these matters are subject to inherent uncertainties and management’s view may change in the future. If an unfavorable final outcome were to occur, there exists the possibility of a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable. We accrue for such items when a liability is both probable and the amount can be reasonably estimated.

ITEM 4.  MINE SAFETY DISCLOSURES

 Our sand mining operations in support of our E&P business, are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977. Information concerning mine safety violations or other regulatory matters required by section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K (17 CFR 229.106) is included in Exhibit 95.1 to this Form 10-K.

PART II

ITEM 5.  MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock is traded on the New York Stock Exchange, or the NYSE, under the symbol “SWN.”  On February 15, 2013, the closing price of our stock was $33.04 and we had 3,110 stockholders of record.  The following table presents the high and low sales prices for closing market transactions as reported on the NYSE.

We have indefinitely suspended payment of quarterly cash dividends on our common stock.

Issuer Purchases of Equity Securities

During 2012, we retired 11,357 shares for the payment of withholding taxes due on employee stock plan share issuances.  All changes in common stock in treasury in 2012 were due to purchases and sales of shares held on behalf of participants in a non-qualified deferred compensation supplemental retirement savings plan. We refer you to Note 1 to our consolidated financial statements in Item 8 of Part II. 

Recent Sales of Unregistered Equity Securities

We did not sell any unregistered equity securities during 2012.

STOCK PERFORMANCE GRAPH

The following graph compares, for the last five years, the performance of our common stock to the S&P 500 Index and the Dow Jones U.S. Exploration & Production Index.  The chart assumes that the value of the investment in our common stock and each index was $100 at December 31, 2007, and that all dividends were reinvested.  The stock performance shown on the graph below is not indicative of future price performance.