ITEM 1.  BUSINESS

Southwestern Energy Company is an independent energy company primarily focused on the exploration for and production of natural gas.  We principally operate our natural gas and oil exploration and production, or E&P, business in four well-established productive regions - the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast.  Today, we derive the vast majority of our operating income and cash flow from our E&P business.  In addition to our core areas of operations, we actively seek to develop new conventional exploration projects as well as unconventional plays, which we refer to as New Ventures, with significant exploration and exploitation potential.  We are also focused on creating and capturing additional value at and beyond the wellhead through our established natural gas distribution, marketing and transportation businesses and our expanding gathering activities.  Our marketing and gathering businesses are collectively referred to as our Midstream Services.  

We operate principally in the following three segments:

1.

Exploration and Production - Our primary business is natural gas and oil exploration, development and production within the United States, with our operations principally located in Arkansas, Oklahoma, Texas, New Mexico and Louisiana.  We engage in natural gas and oil exploration and production through our wholly-owned subsidiaries, SEECO, Inc., Southwestern Energy Production Company (which we refer to as SEPCO) and Diamond “M” Production Company, as well as through Overton Partners, L.L.C. and DeSoto Drilling, Inc., which are both wholly-owned subsidiaries of SEPCO.  SEECO operates exclusively in Arkansas, holds a large base of both developed and undeveloped gas reserves and conducts both the ongoing conventional drilling program in the Arkansas part of the Arkoma Basin and the drilling program for the Fayetteville Shale play, which was announced in 2004.  SEPCO conducts development drilling and exploration programs in the Arkoma Basin, the Permian Basin of Texas and New Mexico, and in Louisiana and East Texas.  Diamond “M” has interests in properties in the Permian Basin of Texas.  DeSoto Drilling, Inc., or DDI, is a newly formed company through which our drilling operations in the Fayetteville Shale play will be conducted.  

2.

Natural Gas Distribution - We are also engaged in the distribution and transmission of natural gas.  Our wholly-owned subsidiary, Arkansas Western Gas Company, which we refer to as Arkansas Western, operates integrated natural gas distribution systems in northern Arkansas serving approximately 148,000 retail customers.  Arkansas Western is the largest single purchaser of SEECO’s gas production.

3.

Midstream Services - Our gas marketing subsidiary, Southwestern Energy Services Company, was formed in 1996 to better enable us to capture downstream opportunities which arise through marketing and transportation activity.  In 2004, we formed a new subsidiary, DeSoto Gathering Company, L.L.C., to engage in gathering activities related to the development of our Fayetteville Shale play. Our Midstream Services segment generates revenue through the marketing of our own gas production and some third-party natural gas and from gathering fees associated with the transportation of natural gas to market.  Our gathering revenues have been insignificant to-date but are expected to increase in the future depending upon the level of production from our Fayetteville Shale area.

Our E&P segment has increasingly contributed to our financial results primarily due to the general increase in natural gas and crude oil commodity prices and the growth in our production volumes.  In 2005, 95% of our operating income and 94% of our earnings before interest, taxes, depreciation, depletion and amortization, or EBITDA, were generated from our E&P business.  Our Natural Gas Distribution and Midstream Services segments generated 2% and 3% of our operating income, respectively, and each generated 3% of our EBITDA in 2005, respectively.  In 2004, our E&P segment generated 90% of our operating income and 91% of our EBITDA, while the Natural Gas Distribution and Midstream Services segments each generated 5% of our operating income and generated 6% and 3% of our EBITDA in 2004, respectively.  In 2003, our E&P, Natural Gas Distribution and Midstream Services segments generated 87%, 7% and 6% of our operating income, respectively, and 87%, 9% and 4% of our EBITDA, respectively.  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 as derived from our audited financial information.

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Our Business Strategy

We are focused on providing long-term growth in the net asset value of our business, which we achieve in our E&P business through the drillbit.  Within the E&P segment, we prepare economic analyses for each of our drilling and acquisition opportunities and rank them based upon the expected present value added for each dollar invested, which we refer to as PVI.  The PVI of the future expected cash flows for each project is determined using a 10% discount rate. We target creating at least $1.30 of discounted 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 E&P business strategy are:

·

Exploit and Develop Existing Asset Base .  We seek to maximize the value of our existing asset base by developing and exploiting properties that have production and reserve growth potential while also controlling per unit production costs.  We intend to add proved reserves and increase production through the use of advanced technologies, including detailed technical analysis of our properties, and by drilling infill locations and selectively recompleting existing wells.  We also plan to drill step-out wells to expand known field limits.

·

Grow Through New Exploration and Development Activities .  We actively seek to develop natural gas and oil plays as well as New Ventures.  New prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria.  Our Fayetteville Shale play is an outgrowth of our focus on new exploration and development projects.

·

Rationalize Our Property Portfolio and Acquire Selective Properties .  We actively pursue opportunities to reduce production costs of our properties and improve overall return, including selling marginal properties from our E&P portfolio of assets and acquiring producing properties and leasehold acreage in the regions in which we operate.   We also seek to acquire operational control of properties with significant unrealized exploration and exploitation potential.

·

Maximize Efficiency Through Economies of Scale .   In our key operating areas, the concentration of our properties allows us to achieve economies of scale in our drilling and production operations that result in lower costs.  In addition, we expect DDI to achieve economies of scale with respect to the drilling of our wells in the Fayetteville Shale play.

Recent Developments

2006 Planned Capital Expenditures and Production Guidance.  In December 2005, we announced a planned capital investment program for 2006 of $830.1 million, an increase of 72% over our 2005 capital program.  Our 2006 capital program includes $770.3 million for our E&P segment (including $78.5 million invested in drilling rigs), $37.5 million for our Midstream Services segment and $11.9 million for improvements to our utility systems and $10.4 million for other corporate purposes.  The increased capital program is expected to be funded by internally-generated cash flow, the remaining net proceeds from our September 2005 equity offering (discussed below) and borrowings under our revolving credit facility.  We also announced our targeted 2006 oil and gas production of approximately 74.0 to 76.0 Bcfe, an increase of approximately 21% to 25% over our production in 2005.

Two-For-One Stock Splits.   On November 17, 2005, we distributed additional shares of our common stock to our stockholders in a two-for-one stock split that was declared by our board of directors in October 2005.  We also effected a two-for-one stock split with respect to our common stock in June 2005.

Utility Receives Rate Adjustment.   Effective October 31, 2005, in response to a request for a $9.7 million annual rate increase, the Arkansas Public Service Commission, or APSC, approved a rate increase for our utility of $4.6 million annually, exclusive of costs to be recovered under Arkansas Western’s purchase gas adjustment clause.  

Follow-on Equity Offering.  In September 2005, we consummated an underwritten offering of 9,775,000 shares of our common stock.  The net proceeds of the offering were approximately $580.0 million after deduction of underwriting discounts and offering expenses payable by us.  Of the net proceeds, $186.7 million was used to pay down outstanding indebtedness under our revolving credit facility, $125.0 million was used to pay our 6.70% Notes due December 2005 and the remainder was invested in short-term cash equivalents pending use for future working capital and/or capital expenditure needs.

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Exploration and Production

In 1943, we commenced a program of exploration for and development of natural gas reserves in Arkansas for supply to our utility customers.  In 1971, we initiated an E&P program outside Arkansas, unrelated to the utility’s requirements.  Since that time, our E&P activities outside Arkansas have expanded substantially.  In 1998, we brought in a new executive management team for our E&P business.  Our executives have assembled a high-quality team of management and technical professionals with knowledge and experience in the geologic basins in which we have operations, including experienced explorationists with proven track records of finding natural gas and oil. Our E&P business is organized into asset management teams based on the geographic location of our exploration and development projects.

Areas of Operation

We operate our E&P business in four general regions - the Arkoma Basin, East Texas, the Permian Basin and the onshore Gulf Coast. Operating income from our E&P segment was $234.8 million in 2005, up from $164.6 million in 2004 and $84.7 million in 2003.  The increases in 2005 and 2004 were due to increased production volumes and higher realized prices, partially offset by increases in operating costs and expenditures.  EBITDA from our E&P segment was $325.9 million in 2005, compared to $231.1 million and $131.4 million, respectively, in 2004 and 2003.  The increases in 2005 and 2004 were due to increased production volumes and higher realized prices, partially offset by increases in operating costs and expenditures.  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 with our net income.  

Our estimated proved natural gas and oil reserves were 826.8 Bcfe as of December 31, 2005, up from 645.5 Bcfe at year-end 2004 and 503.1 Bcfe at year-end 2003.  The overall increase in total reserves in the past three years is primarily due to the accelerated development of our Overton Field in East Texas, the discovery and development of the Fayetteville Shale play in Arkansas, our successful conventional drilling program in the Arkoma Basin, and development of a new field in the Permian Basin.  Our year-end 2005 reserves had a pre-tax PV-10 value of $1,986.4 million and an after-tax PV-10 value, or standardized measure, of $1,420.8 million, up from $892.3 million at year-end 2004 and $716.4 million at year-end 2003.  We refer you to Note 6 in the consolidated financial statements for a discussion of our standardized measure of discounted future cash flows related to our proved natural gas and oil reserves and 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 - Forward-Looking Information” 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 93% of our proved reserves were natural gas and 73% were classified as proved developed.  We operate approximately 78% of our reserves, based on our PV-10 value, and our average proved reserves-to-production ratio, or average reserve life, approximated 13.6 years at year-end 2005.  Sales of natural gas production accounted for 92% of total operating revenues for this segment in both 2005 and 2004, as compared with 91% in 2003.  Natural gas production has increasingly generated a substantial portion of total operating revenues as a result of the natural gas focus of our capital investments in the past three years.

In 2005, we replaced 399% of our production volumes by adding 243.1 Bcfe of proved natural gas and oil reserves at a finding and development cost of $1.71 per Mcfe, including a downward reserve revision of 31.7 Bcfe but excluding $35.1 million of capital invested in drilling rigs. In 2004 and 2003, our reserve replacement ratios were 365%

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and 313%, respectively, and our finding and development costs were $1.43 per Mcfe and $1.33 per Mcfe, respectively, including net downward reserve revisions of 12.7 Bcfe in 2004 and 15.5 Bcfe in 2003.  The downward reserve revisions during 2005 were primarily due to minor changes to decline rates for wells at our Overton Field and unexpected declines associated with our Gulf Coast properties.  The negative reserve revisions during 2004 were primarily due to slightly higher decline rates related to some of the wells in our Overton Field in East Texas, while negative revisions in 2003 were primarily due to poorer-than-expected well performance related to our South Louisiana properties.  The increase in our reserve replacement ratio during this time period is primarily due to increased success of our drilling programs in finding new natural gas and crude oil reserves.  The increase in our finding and development costs primarily reflects the general increase in material costs and oilfield service costs to drill and complete wells in our key operating areas.  Additionally, we invested approximately $40.7 million, $14.0 million and $11.0 million during 2005, 2004 and 2003, respectively, in acquiring leasehold positions in our Fayetteville Shale play.  For the period ending December 31, 2005, our three-year average reserve replacement ratio was 364%, and our three-year average finding and development cost was $1.53 per Mcfe, including reserve revisions and excluding our investments in drilling rigs.

Our reserve replacement ratio during 2005, excluding the effect of reserve revisions, was 450%, compared to 388% in 2004 and 351% in 2003.  Our finding and development cost, excluding revisions and our investments in drilling rigs, was $1.51 per Mcfe in 2005, compared to $1.34 per Mcfe in 2004 and $1.18 per Mcfe in 2003.  The increase in our finding and development costs during this time period were primarily due to higher costs for drilling and other field services.  Excluding reserve revisions and our investments in drilling rigs, these three-year averages were 402% and $1.38 per Mcfe, respectively.

The following table provides information as of December 31, 2005 related to proved reserves, well count, and net acreage, and 2005 annual information as to production and capital expenditures, for each of our core operating areas, for our New Ventures and overall:

(1) Our Fayetteville Shale play capital investments include $35.1 million invested in drilling rigs and $40.7 million in leasehold acquisition costs. New Ventures’ capital investments include $4.4 million relating to two wells in the Angelina River Trend project that are now part of our East Texas program.

(2) Includes 123,442 net developed acres and 1,431 net undeveloped acres in our Conventional Arkoma Basin operating area that are also within our Fayetteville Shale focus area but not included in the Fayetteville Shale acreage in the table above.

Arkoma Basin .  We have traditionally operated in a portion of the Arkoma Basin that is primarily within the boundaries of our utility gathering system in Arkansas, which we refer to as the “Fairway.”  In recent years, we have expanded our activity in the Arkoma Basin south and east of the traditional Fairway area and into the Oklahoma portion of the basin. Our drilling program in the Arkoma Basin is comprised of both conventional and unconventional activities.  We refer to our drilling program targeting stratigraphic Atokan-age objectives in Oklahoma and Arkansas as our “conventional Arkoma” drilling program. Our Fayetteville Shale play represents our entire unconventional drilling program in the Arkoma Basin.  At December 31, 2005, we had approximately 372.0 Bcf of natural gas reserves in the Arkoma Basin, representing approximately 45% of our total reserves, up from 247.0 Bcf at year-end 2004 and 211.7 Bcf at year-end 2003.  

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Conventional Arkoma Program.   Our conventional Arkoma drilling program continues to provide a solid foundation for our E&P program and represents a significant source of our production and reserves.  Approximately 271.0 Bcf of our reserves at year-end 2005 were attributable to our conventional Arkoma wells.  During 2005, we participated in 71 wells with 61 producers, five dry holes and five wells in progress at year-end, resulting in a 92% drilling success rate while adding 51.7 Bcf of gas reserves at a finding and development cost of $1.25 per Mcf, including a net downward reserve revision of 0.7 Bcf.  This compares to finding and development costs of $1.11 per Mcf in the basin in 2004 and $0.79 per Mcf in 2003, including net upward reserve revisions of 4.5 Bcf and 13.1 Bcf, respectively.  Excluding revisions, finding and development costs would have been $1.23 per Mcf in both 2005 and 2004 and $1.14 per Mcf in 2003.  The increase in our finding costs during this time period was primarily due to higher costs for drilling and other oil field services.  Our gas production from our conventional drilling program in the Arkoma Basin was 20.2 Bcf during 2005, or approximately 55.5 MMcf per day, compared to 20.1 Bcf in 2004 and 18.9 Bcf in 2003.  The increase in production over this time period was primarily due to a greater number of wells drilled in the basin and higher production volumes from our Ranger Anticline area.  

Our conventional activities in the Arkoma Basin continue to generate a significant amount of our cash flow.  With three-year average finding and development costs of $1.06 per Mcf, including revisions (or $1.21 per Mcf excluding revisions), and three-year average production, or lifting, costs of $0.54 per Mcf (including production taxes), our cash margins from our conventional drilling program in the Arkoma Basin are very attractive.  Lifting costs continued to be low during 2005 at $0.68 per Mcf (including production taxes), compared to $0.48 per Mcf in 2004 and $0.46 per Mcf in 2003.  While lifting costs from our conventional drilling program have increased primarily due to higher oil field service costs, we continue to be one of the lowest cost producers in the industry.  

Our strategy in the Fairway is to delineate new geologic prospects and extend previously identified trends using our extensive database of regional structural and stratigraphic maps.  In recent years, we have extended our development program into the Oklahoma portion of the Arkoma Basin, and into other areas of the basin in Arkansas that have been lightly explored to date.  Since 2002, we have significantly increased our drilling activity in our Ranger Anticline prospect area, located at the southern edge of the Arkansas portion of the basin.

Our wells at Ranger have primarily targeted the Upper and Lower Borum tight gas sands between 5,000 and 8,000 feet in depth.  In 2005, wells completed in the Borum had average estimated ultimate gross reserves of 1.2 Bcf per well.  As our understanding of the geology at Ranger has grown, the potentially productive area in the field has expanded.  In 2005, we extended the field boundaries to the east approximately 9 miles by drilling four successful wells in shallower Basham, Nichols and Turner tight gas sands.  The Borum sands in these wells were not commercially productive. These shallower sands are between 3,500 and 4,500 feet in depth had average estimated ultimate gross reserves of 0.5 Bcf per well.

We drilled our first successful well at Ranger in 1997, and through year-end 2005, we successfully drilled 77 out of 87 wells, adding 82.1 net Bcf of reserves at a finding cost of $1.07 per Mcf, including reserve revisions.  During 2005, we successfully completed 34 out of 37 wells (excluding three wells in progress at year-end 2005), which added 19.3 Bcf of new reserves at a finding and development cost of $2.19 per Mcf, including downward reserve revisions of 4.0 Bcf.  Excluding reserve revisions, our finding and development cost at Ranger was $1.81 per Mcf.  During 2005, our finding and development cost increased due to higher drilling and oil field service costs, combined with lower reserves per well due to completions in the shallower Basham, Nichols and Turner sands.  A large portion of our increased costs were related to a greater amount of directional drilling which is more costly and time consuming.  While the majority of the wells planned to be drilled at Ranger during 2006 will not require directional drilling, we expect that the general trend of higher costs for drilling and other oil field services will continue with future development wells in the field.  Net production from the field during 2005 was 5.6 Bcf, up from 3.5 Bcf produced in 2004 and 1.7 Bcf produced in 2003.  Our average working interest in the 77 successful wells drilled through December 31, 2005 is 78% and our average net revenue interest is 64%.

We continue to increase our acreage position at Ranger and, as of December 31, 2005, we held approximately 12,800 gross developed acres and 49,900 gross undeveloped acres and had regulatory approval for well spacing at a minimum distance of 560 feet between wells at Ranger. Our average working interest in our gross undeveloped acreage position at Ranger is 73%.  We believe that Ranger holds significant future development potential.

Late in the third quarter of 2005, we drilled the initial exploratory well on our Midway prospect, targeting the Pennsylvanian and Ordovician section. The USA #1-24 well encountered approximately 230 feet of net pay by electric log calculation in the Pennsylvanian age Borum sands, which is the main producing horizon in the Ranger Anticline area. We are testing these sands and will determine the development potential based on the results. We have approximately 20,300 gross undeveloped acres in our Midway prospect area.

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Our conventional Arkoma Basin drilling program continues to be a significant focus for our capital program and we intend to allocate funds to our development drilling and workover programs at a level that, at a minimum, maintains our production and reserve base in this area.  In 2006, we plan to invest approximately $89.6 million in the conventional Arkoma program and will drill approximately 100 to 110 wells, including 50 to 60 wells at the Ranger Anticline.

Fayetteville Shale Play.  Our emerging Fayetteville Shale play is now a primary focus of our E&P business.  The Fayetteville Shale is an unconventional gas reservoir located on the Arkansas side of the Arkoma Basin, ranging in thickness from 50 to 325 feet and ranging in depth from 1,500 to 6,500 feet.  The shale is a Mississippian-age shale that is the geologic equivalent of the Caney Shale found on the Oklahoma side of the Arkoma Basin and the Barnett Shale found in north Texas.  Since we announced the Fayetteville Shale play in August 2004, we have increased our capital investments as we have accelerated our drilling program in the play area.  In 2005, as part of our capital investments, we entered into agreements for the fabrication of ten new drilling rigs to be dedicated to drilling wells in the play.  The drilling operations will be conducted through our newly formed subsidiary, DeSoto Drilling, Inc., or DDI.  At December 31, 2005, DDI had 45 employees and we expect DDI to have a total of approximately 275 employees by year end 2006.

At December 31, 2005, we held a total of approximately 865,000 net acres in the play area (720,000 net undeveloped acres, 20,000 net developed acres held by Fayetteville Shale production and approximately 125,000 net developed acres held by conventional production).  As of December 31, 2005, we had spud a total of 88 wells in the play, 86 of which were operated by us and two of which were outside-operated wells.  Of the 88 wells spud, 67 were drilled during 2005 and 21 were drilled in 2004.  The wells are located in 15 separate pilot areas located in seven counties in Arkansas and, as of December 31, 2005, 54 were producing, 13 were in some stage of completion or waiting on pipeline hook-up and four were shut-in due to marginal performance or temporarily abandoned.  The remaining 17 wells were in the drilling phase at year-end, including 13 horizontal wells which had been drilled through the vertical section with a smaller spudder rig and will be re-entered with a larger rig capable of drilling the horizontal section.

Our results to date indicate that optimal development of the resource will primarily require horizontal wells.  At December 31, 2005, 37 of the 88 wells spud are designated as horizontal wells, 13 of which were producing, five were completing, four were drilling, two were temporarily abandoned and 13 wells had been drilled through the vertical section.  The average initial test rate for 12 of the 13 completed horizontal wells is 2.5 MMcf per day.  Our first horizontal well, the Vaughan #4-22-H, is excluded because it is not analogous as wellbore problems limited the fracture stimulation treatment.  The well costs for the most recently completed horizontal wells have ranged between $1.4 million and $1.8 million per well, excluding non-recurring costs.  The horizontal wells drilled through December 31, 2005, have had an average vertical depth of 3,200 feet and an average lateral length of 2,000 feet, and have taken 15 to 20 days on average to reach total depth.  

The wells we have drilled in the Fayetteville Shale play area represent a very small sample of our large acreage position.  During 2006, we expect to continue the evaluation of our acreage position in the Fayetteville Shale play by testing an additional 24 to 30 pilot areas.  As we continue to gather data about our prospects in 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 “Risk Factors - Our future reserve and production growth is dependent in part on the success of our Fayetteville Shale drilling program, which has a limited operational history and is subject to change” in Item 1A of Part I of this Form 10-K.

During 2005, we invested approximately $154.5 million in our Fayetteville Shale play, which included $67.4 million to spud 67 wells, $40.7 million for leasehold acquisition, $35.1 million towards the fabrication of ten new drilling rigs to be utilized in the play, $4.3 million for seismic and $7.0 million in capitalized costs.  In 2004, we invested approximately $27.9 million, which included $11.6 million in capital for drilling 21 wells, $14.0 million for leasehold acquisition, and $2.3 million for other capitalized costs.  In 2003, we invested approximately $11.0 million for leasehold acquisition.  Net gas production from the Fayetteville Shale play during 2005 was 1.8 Bcf, compared to 0.1 Bcf produced during 2004.  Total proved gas reserves booked in the play as of year-end 2005 totaled 101.0 Bcf from a total of 177 locations, of which 54 were proved developed producing, 6 were proved developed non-producing and 117 were proved undeveloped.  Of the 177 locations, 131 were horizontal. The average proved reserves for each of the horizontal wells included in our year-end reserves was approximately 0.95 gross Bcf per well.  Netherland, Sewell & Associates, Inc. ("NSA"), our independent petroleum engineering firm, has indicated that their estimate of the average proved reserves for the Fayetteville Shale play wells are lower than our estimates and that, to resolve these differences, additional performance data are required.  We estimate average ultimate gross production for these wells of 1.3 to 1.5 Bcf per horizontal well, based on the limited production data through December 31, 2005 and our reservoir simulation shale gas model.  Therefore, as our horizontal wells continue to produce over time, our proved reserves estimate of 0.95 gross Bcf on a per well basis could be revised upward in the future.  Total proved gas reserves booked in the play in 2004 totaled 7.5 Bcf from a total of 20 vertical wells, 10 of which were classified as proved, undeveloped locations, for an average estimated ultimate recovery

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per well of 430,000 Mcf (375,000 Mcf net).  At the end of 2005, our proved reserves included 5.0 net Bcf associated with 43 vertical wells.

As required, we file applications with the Arkansas Oil and Gas Commission, or the AOGC, for approval of field rules for our pilot area once we have drilled the required number of wells.  Through December 31, 2005, the AOGC

approved field rules for four fields in the Fayetteville Shale play area located in Conway, Van Buren and Faulkner counties.  Subsequent to December 31, 2005 and through February 20, 2006, the AOGC approved field rules for another field, the New Quitman Field, located in Cleburne and Faulkner counties in Arkansas.  For each field, the AOGC approved governmental sections of approximately 640 acres as the drilling unit and well spacing requirements within each drilling unit of 560 feet minimum distance between completions in common sources of supply within the Fayetteville Shale formation, up to a maximum of 25 wells per drilling unit.  At December 31, 2005, based on the assumptions contained in the field rule applications for these fields, we estimated the expected drainage from horizontal wells to be less than 80 acres per well based on existing microseismic data and reservoir simulation modeling.  There can be no assurance that we will be successful in obtaining the same size drilling unit or the same spacing in the field rules for our other pilot areas or for our other Fayetteville Shale acreage as a whole.  We refer you to “Risk Factors - We may have difficulty drilling all of the wells that are necessary to hold our Fayetteville Shale acreage before the initial lease terms expire, which could result in the loss of certain leasehold rights. ”  

In 2006, we expect to invest $338.3 million in the Fayetteville Shale play, which would include drilling between 175 to 200 wells.  Of those wells, nearly all will be horizontal wells.  Our strategy going forward is to increase our production through development drilling while also determining the economic viability of the undrilled portion of our acreage through drilling in new pilot areas.  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, the extent to which we can replicate the results of our most successful Fayetteville Shale wells on our other Fayetteville Shale acreage as well as the natural gas and oil commodity price environment.  We refer you to "Risk Factors - Our drilling plans for the Fayetteville Shale play are subject to change" in Item 1A of Part I of this Form 10-K.

East Texas .  Our East Texas operations are primarily located in the Overton Field in Smith County, Texas, and our Angelina River Trend located in southern Nacogdoches County, Texas.

Overton Field - Our original interest in the Overton Field (which was approximately 10,800 gross acres) was acquired in April 2000 for $6.1 million.  At December 31, 2005, we held approximately 24,400 gross acres with an average working interest in the Overton Field of 96% and average net revenue interest of 77%.  

The Overton Field produces from four Taylor series sands in the Cotton Valley formation at approximately 12,000 feet.  When we acquired the field in April 2000, it was primarily developed on 640-acre spacing, or one well per square mile.  Analogous Cotton Valley fields in the area have been drilled to 80-acre spacing, and in some cases to 40-acre spacing.  In 2003, we received regulatory approval from the Texas Railroad Commission to allow downspacing at Overton to optional 80-acre spacing.  We also received approval in 2003 to drill four wells at locations that were effectively 40-acre spaced wells. Of the four test wells drilled at 40-acre spacing, three wells indicated pressures near original reservoir pressures and one showed partial depletion.  Data from the four 40-acre spaced wells indicated that a significant portion of the field would likely require 40-acre spaced wells to adequately develop the field.  During the first quarter of 2004, we received regulatory approval to allow downspacing at Overton to optional 40-acre spacing.

In 2005, we drilled and completed a total of 80 wells, of which 52 were 40-acre spaced wells. This compares to 83 wells drilled and completed in 2004 and 57 wells in 2003.  We have experienced a 100% success rate at Overton since we began our development drilling program in 2001. Daily gross production at the Overton Field has increased from approximately 2.0 MMcfe in March 2001 to approximately 109.7 MMcfe at year-end 2005 resulting in net production of 26.7 Bcfe during 2005, compared to 21.8 Bcfe in 2004 and 13.6 Bcfe in 2003.  New wells drilled in the field during 2005 averaged approximately $1.8 million to drill and complete, had average initial production rates of approximately 3.0 MMcfe per day and had average estimated ultimate gross reserves of 1.8 Bcfe per well.  Our average production costs (including production taxes) were $0.56 per Mcfe in 2005, compared to $0.50 per Mcfe in 2004 and $0.45 per Mcfe in 2003.  The increases in our unit production costs were primarily due to higher production taxes resulting from higher realized commodity prices, partially offset by increased production.

Our proved reserves in East Texas increased to 368.7 Bcfe at year-end 2005, or 45% of our total reserves, of which 352.7 Bcfe of reserves were in our Overton Field.  Our reserves at Overton were up significantly from 296.6 Bcfe at year-end 2004 and 196.3 Bcfe at year-end 2003, primarily due to the acceleration of our infill drilling program which began in early 2003.  We invested approximately $158.0 million at the Overton Field during 2005 which resulted in proved

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reserve additions of 82.8 Bcfe at a finding and development cost of $1.91 per Mcfe, including a net downward reserve revision of 18.8 Bcfe.  This compares to finding and development costs of $1.20 per Mcfe in 2004 and $0.98 per Mcfe in 2003, including net downward reserve revisions of 19.2 Bcfe and 3.7 Bcfe, respectively.  Excluding such revisions, our finding and development costs at Overton were $1.56 per Mcfe in 2005, $1.04 per Mcfe in 2004 and $0.95 per Mcfe in 2003.  Our finding cost increased in 2005 and 2004 primarily due to slightly lower reserves per well combined with higher costs for drilling and other oil field services.  We expect that this trend will continue with future development wells in the field.  The average estimated ultimate recovery of gas and oil reserves from new wells completed in 2005 was approximately 1.8 gross Bcfe per well, compared to 2.0 gross Bcfe per well in 2004 and 2.2 gross Bcfe per well in 2003.  The consistent decrease in gross reserve per well is primarily due to our drilling of locations with the highest estimated ultimate recovery earlier in our development program and is expected to continue.

In 2006, we plan to invest approximately $161.5 million at Overton and drill approximately 83 wells.  Based on reasonable gas price assumptions, the level of industrywide cost increases for services and materials and our investment hurdle rate, it appears that our drilling program at Overton could be extended into 2007.  

Angelina River Trend - Our Angelina River Trend is a collection of four new development areas, located primarily in Nacogdoches County, Texas.  At December 31, 2005, we held approximately 11,000 gross undeveloped acres and 3,000 gross developed acres.  Our average working interest in this area is 72% and our average net revenue interest is 56%.  Through December 31, 2005, we had drilled nine wells with 100% success in this trend primarily targeting the Travis Peak formation.  Net production from the area was 0.9 Bcfe in 2005.  Gross initial production rates from wells drilled during 2005 ranged from 1.7 to 4.4 MMcfe per day.  Our proved reserves in the area were 13.5 Bcfe at year-end 2005, compared to 0.5 Bcfe at year-end 2004.  The average estimated ultimate recovery of gas and oil reserves from the wells completed in 2005 was approximately 1.6 gross Bcfe per well with an average drill and complete cost of $2.5 million per well.  In 2005, we invested $18.7 million in the Angelina River Trend, excluding $4.4 million of capital expenditures for two of the wells that is included in our New Ventures capital expenditures.  During 2006, we intend to explore the growth potential of the Angelina River Trend and are planning to invest $34.5 million to drill a total of 16 wells in the area during the year.

Permian Basin .  We have had a drilling program since 1997 in the Permian Basin, which is primarily located in west Texas and southeast New Mexico.  At December 31, 2005, our proved reserves in the Permian Basin were 58.6 Bcfe, compared to 60.8 Bcfe in 2004 and 55.6 Bcfe in 2003.  Our production in the basin during 2005 was 6.9 Bcfe, or approximately 18.9 MMcfe per day, compared to 7.1 Bcfe in 2004 and 4.2 Bcfe in 2003.  The decrease in reserves and production during 2005 was primarily due to the natural decline in these properties, partially offset by new reserves added from drilling.  The increase in reserves and production in 2004 from 2003 was primarily due to increased volumes from our River Ridge discovery in Eddy County, New Mexico, and subsequent development of that field.  Our production costs (including production taxes) averaged $1.76 per Mcfe in 2005, compared to $1.21 per Mcfe in 2004 and $1.15 per Mcfe in 2003.  The increases in production costs were primarily due to higher service costs and increased production taxes resulting from higher gas and oil commodity prices.  In 2005, we invested $15.1 million in the Permian Basin, drilling 16 wells, of which 15 were successful, resulting in reserve additions of 4.7 Bcfe.  Our finding and development cost in the Permian was $3.21 per Mcfe, including a net downward reserve revision of 0.9 Bcfe.  This compares to finding and development costs of $2.09 per Mcfe in 2004 and $3.44 per Mcfe in 2003, including a net upward reserve revision of 2.6 Bcfe in 2004 and a net downward revision of 7.1 Bcfe in 2003.  Excluding such revisions, our finding and development costs in the Permian Basin were $2.70 per Mcfe in 2005, $2.62 per Mcfe in 2004 and $0.95 per Mcfe in 2003.  The increase in our finding and development cost in 2005 was due to overall higher service costs.  The increase in finding cost in 2004 was primarily due to the acquisition of additional working interest in our River Ridge discovery.

In July 2004, we acquired additional working interest in our River Ridge field for $14.2 million, which consolidated our position in this property and allowed us to gain additional development opportunities.  The acquisition increased our working interest in an existing producing well to 50% from 12.5%, and gave us a 50% working interest in another well in which we previously held no interest.  The acquired interest added approximately 5.8 net Bcfe in proved reserves.  Our overall finding and development cost in the field from drilling and this acquisition is $2.20 per Mcfe, including downward reserve revisions of 3.1 Bcfe.  We hold a 50% working interest in this field.  

In 2006, we plan to invest approximately $15.9 million in our Permian Basin program to drill approximately 12 exploration and exploitation wells.

Gulf Coast .  Our Gulf Coast operations are located in the onshore areas of Texas and Louisiana.  Since our first discovery in December 1999, the efforts of our exploration program have resulted in 10 successful wells out of 23 wildcats drilled in South Louisiana.  We have not had a significant discovery in South Louisiana since 2001 and our reserves in the area are naturally declining.  Our proved reserves in these areas totaled 27.5 Bcfe at December 31, 2005, compared to 38.6

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Bcfe at year-end 2004 and 39.5 Bcfe at year-end 2003.  Approximately 9.0 Bcfe of reserves at December 31, 2005, were located in Louisiana.  The decline in reserves during 2004 and 2005 was primarily due to the natural decline in these properties, partially offset by new reserve additions from drilling.  Net production from this area in 2005 was 3.9 Bcfe, or approximately 10.7 MMcfe per day, compared to 4.6 Bcfe in 2004 and 4.5 Bcfe in 2003.  Production costs (including production taxes) averaged $1.67 per Mcfe during 2005, compared to $1.39 per Mcfe in 2004 and $1.23 per Mcfe in 2003. The increase in our unit production costs over this time period was primarily due to the decline in production volumes from these properties, as well as general increases in operating costs.  In 2005, we invested $7.9 million in this area, adding 3.7 Bcfe of reserves which were more than offset by downward reserve revisions of 10.2 Bcfe.  This compares to net downward reserve revisions of 0.6 Bcfe in 2004 and 17.7 Bcfe in 2003.  The downward reserve revisions over the last three years have been primarily due to poorer-than-expected well performance related to our South Louisiana properties.  Excluding such revisions, our finding and development costs in the Gulf Coast area were $2.14 per Mcfe in 2005, $3.65 per Mcfe in 2004 and $6.00 per Mcfe in 2003.  The relatively high finding costs during this time period was primarily due to the lack of significant success in our South Louisiana exploration program over the last three years.

During 2004 and 2005, we reduced our exploration activities in the Gulf Coast region primarily because our drilling efforts were not meeting our economic criteria.  In 2006, we plan to invest $8.6 million in the Gulf Coast area which includes drilling up to three wells which are developmental in nature.  

Other Exploration and New Ventures .  We have personnel dedicated to the research and identification of active and potential plays, focusing on both conventional exploration plays and unconventional plays (including coalbed methane, shale gas and basin-centered gas) as well as the technological aspects such as horizontal drilling and fracture techniques.  New prospects are evaluated based on repeatability, multi-well potential and land availability as well as other criteria.  

At December 31, 2005, we held 116,633 net undeveloped acres in areas of the United States outside of our core operating areas in connection with New Ventures that we are pursuing.  This compares to 47,596 net undeveloped acres held at year-end 2004 and 345,310 net undeveloped leasehold acres held at year-end 2003.  Of the 116,633 net undeveloped acres held at year-end 2005, approximately 49,000 acres are located in Culberson County, Texas, in the emerging Barnett Shale play in the Permian Basin.  We anticipate drilling a test well for the Barnett Shale interval in the second quarter of 2006. Of the 345,310 net undeveloped acres held at year-end 2003, approximately 343,351 acres related to our Fayetteville Shale play in Arkansas, which is now part of our Arkoma operations.  

In 2005, we invested approximately $25.7 million in our New Ventures and drilled a total of six exploration wells, of which three were successful and one was in progress at year-end.  Our three discoveries in 2005 were located in East Texas.  Two of the wells are now included in our East Texas operations as part of our Angelina River Trend development project.  The third East Texas discovery was at our Pines prospect located in Marion County.  Late in the third quarter of 2005, we spudded a deep Arbuckle test northeast of our Ranger Anticline area in the Arkoma Basin.  Although the Arbuckle objective did test natural gas, it did not produce at economic rates.  We are currently completing this well in the uphole Borum sand, which is the main producing horizon in the Ranger Anticline area.  During 2005, we also drilled an exploration well to test the Jackfork objective in Perry County, Arkansas, which was a dry hole and a new coalbed methane test in Sweetwater County, Wyoming that was unsuccessful.  

In 2004, we invested approximately $1.5 million in New Ventures, excluding the Fayetteville Shale play, which included drilling one exploration dry hole in another coalbed methane play.  In 2003, we invested approximately $11.0 million in leasehold, including our Fayetteville Shale play.  However, we did not drill any wells related to the Fayetteville Shale play or other New Ventures projects during 2003.  

In 2006, we plan to invest approximately $28.9 million in exploration projects and $14.5 million in New Venture projects, including drilling up to 18 exploration and unconventional wells in the continental United States.

Acquisitions and Divestitures

In 2005, there were no significant acquisitions of natural gas or crude oil producing properties.  

In 2004, we purchased 5.8 Bcfe of proved reserves for $14.2 million at an average cost of $2.45 per Mcfe.  Almost all of this investment related to the acquisition of additional working interest in our River Ridge discovery in Lea County, New Mexico.

In 2003, we purchased an aggregate of 1.1 Bcfe of proved reserves for $3.0 million, at an average cost of $2.73 per Mcfe. The transactions included working interests in our core Arkoma Basin, Overton Field and Permian Basin

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producing areas.  The average cost per Mcfe was higher than for prior acquisitions due to the potential existence of future drilling opportunities beyond the existing production.

Capital Expenditures

We invested a total of $451.3 million in our E&P program and participated in drilling 247 wells during 2005.  Of these drilled wells, 197 were successful, eight were dry and 42 were still in progress at year-end.  Our investments have continued to focus primarily on our lower-risk, high-return conventional drilling programs in East Texas and the Arkoma Basin that have driven our production and reserve growth for the past three years.  These drilling programs respectively accounted for 41% and 14% of our E&P capital investments in 2005, with approximately $183.6 million invested in East Texas and $64.5 million invested in our conventional Arkoma Basin drilling program.  Our Fayetteville Shale resource play emerged as a significant focus of our capital expenditures in 2005 as we accelerated our drilling program in the play.  During 2005, we invested approximately $119.4 million in our Fayetteville Shale play, or 26% of our E&P capital investments.  In addition, we invested approximately $15.1 million in the Permian Basin, $7.9 million in the Gulf Coast, $25.7 million in Exploration and New Ventures and $35.1 million towards the purchase of drilling rigs and related equipment.  

Of the $451.3 million invested in 2005, approximately $35.6 million was invested in exploratory drilling, $287.5 million in development drilling and workovers, $60.5 million for leasehold acquisition and seismic expenditures, $0.1 million for producing property acquisitions, $35.1 million towards the purchase of drilling rigs and related equipment and $32.5 million in capitalized interest and expenses and other technology-related expenditures.  During 2004, we invested a total of $282.0 million in our E&P business and participated in 204 wells, and in 2003 we invested $170.9 million and participated in 139 wells.  The increases in capital investments and wells drilled during this time was primarily due to the acceleration of our development drilling program at our Overton Field, an increase in conventional drilling activity at our Ranger Anticline area in the Arkoma Basin, and leasehold investments and drilling in our Fayetteville Shale play.

In 2006, we intend to invest approximately $770.3 million in our E&P program, an increase of approximately 71% over our capital investment level in 2005.  We continue to be focused on our strategy of adding value through the drillbit, as approximately 80% of our 2006 E&P capital is allocated to drilling, excluding our capital investments in drilling rigs.  A primary focus of our E&P business is now the Fayetteville Shale play, and we plan to significantly increase our activity and investment in the play to approximately $338.3 million in 2006.  Our investments in 2006 will also be focused on our lower-risk conventional drilling programs in East Texas and the Arkoma Basin.  We plan to invest approximately $196.0 million and $89.6 million in our East Texas and conventional Arkoma Basin programs, respectively, in 2006.  The remainder of our E&P capital will be allocated to exploration and exploitation in the Permian Basin ($15.9 million), the onshore Gulf Coast ($8.6 million), various other exploration and New Venture projects ($43.4 million) and the balance of the purchase price of drilling rigs and related equipment ($78.5 million).  

Of the $770.3 million allocated to the 2006 E&P capital budget, approximately $523.0 million will be invested in development drilling, $25.0 million in exploratory drilling, $70.6 million for land and seismic, $78.5 million for drilling rigs and related equipment, $73.2 million in capitalized interest and expenses and other 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 Expenditures” for a discussion of our planned capital expenditures in 2006.

Other Revenues

Other revenues and operating income for 2005, 2004 and 2003 also included pre-tax gains of $3.1 million, $4.5 million and $3.1 million, respectively, related to the sale of gas-in-storage inventory.  

Sales and Major Customers

Our daily natural gas equivalent production averaged 167.1 MMcfe in 2005, up 13% from 148.2 MMcfe in 2004 and 112.7 MMcfe in 2003.  Our natural gas production was 56.8 Bcf in 2005, compared to 50.4 Bcf in 2004 and 38.0 Bcf in 2003.  The increase in 2005 production resulted primarily from a 5.4 Bcfe increase in production from our Overton Field in East Texas and a 1.9 Bcfe increase in our Arkoma production, primarily related to our Fayetteville Shale play.  Production during 2005 was reduced by the effects of curtailment of a portion of our Overton Field production due to repairs of a transmission line that is not operated by us and by the effects of Hurricane Katrina. Combined, these events reduced our production by approximately 1.0 Bcfe.  The increase in 2004 production resulted primarily from an 8.2 Bcfe increase in production from our Overton Field in East Texas, a 1.3 Bcfe increase in our Arkoma Basin production, and 3.2 Bcfe from our River Ridge discovery in New Mexico.

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We also produced 705,000 barrels of oil in 2005, compared to 618,000 barrels of oil in 2004 and 531,000 barrels in 2003.  Our oil production increased during 2005 primarily due to increased oil production from East Texas and the Permian Basin.  Our oil production increased in 2004 due to increased oil production from our River Ridge discovery in the Permian Basin.  For 2006, we are targeting our total natural gas and crude oil production to be approximately 74.0 Bcfe to 76.0 Bcfe, which equates to a growth rate of approximately 21% to 25% above our 2005 production volumes.

Our gas sales to unaffiliated purchasers were 51.7 Bcf in 2005, compared to 45.0 Bcf in 2004 and 32.1 Bcf in 2003.  All of our oil production is sold to unaffiliated purchasers.  This gas and oil production is sold under contracts that reflect current short-term prices and which are subject to seasonal price swings.  These combined gas and oil sales to unaffiliated purchasers accounted for 90% of total E&P revenues in 2005, 89% in 2004 and 86% in 2003.  In 2005, the largest unaffiliated purchaser accounted for 6% of total E&P revenues.

Our utility subsidiary, Arkansas Western is the largest single customer for sales of our gas production.  These sales are made by SEECO primarily under contracts obtained under a competitive bidding process.  We refer you to “Natural Gas Distribution - Gas Purchases and Supply” for further discussion of these contracts.  Sales to Arkansas Western accounted for approximately 9% of total E&P revenues in 2005, 10% in 2004 and 12% in 2003.  SEECO’s sales to Arkansas Western were 5.1 Bcf in 2005, compared to 5.4 Bcf in 2004 and 5.9 Bcf in 2003.  Sales to Arkansas Western are primarily driven by the utility’s changing supply requirements due to variations in the weather and SEECO’s ability to obtain gas supply contracts that are periodically placed out for bids.  SEECO’s gas production provided approximately 38% of the utility’s requirements in 2005, 40% in 2004 and 41% in 2003.  We also sell gas directly to industrial and commercial transportation customers located on Arkansas Western’s gas distribution systems.  SEECO also owns an unregulated natural gas storage facility that has historically been utilized to help meet its peak seasonal sales commitments.  The storage facility is connected to Arkansas Western’s distribution system.

We expect future increases in our gas production to come primarily from sales to unaffiliated purchasers.  Future sales to Arkansas Western’s gas distribution systems will be dependent upon our success in obtaining gas supply contracts with the utility systems.  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 of both affiliated and unaffiliated customers for our production.

We realized an average wellhead price of $6.51 per Mcf for our natural gas production in 2005, compared to $5.21 per Mcf in 2004 and $4.20 per Mcf in 2003, including the effect of hedges.  Our hedging activities lowered our average gas price $1.22 per Mcf in 2005, $0.59 per Mcf in 2004, and $0.95 per Mcf in 2003.  Our average oil price realized was $42.62 per barrel in 2005, compared to $31.47 per barrel in 2004 and $26.72 per barrel in 2003, including the effect of hedges.  Our hedging activities lowered our average oil price $11.75 per barrel in 2005, $9.08 per barrel in 2004 and $2.94 per barrel in 2003.

We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude 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. At December 31, 2005, we had hedges in place on 50.9 Bcf of 2006 gas production, 40.0 Bcf of 2007 gas production, 2.0 Bcf of 2008 gas production and 120,000 barrels of 2006 oil production.  Subsequent to December 31, 2005 and prior to February 20, 2006, we hedged 6.0 Bcf of 2008 gas production under costless collars with floor prices ranging from $7.00 to $9.00 per Mcf and ceiling prices ranging from $12.55 to $15.80 per Mcf.  As of December 31, 2005, we had hedges in place on approximately 70% to 75% of our targeted 2006 gas production and approximately 15% to 20% of our targeted crude oil production.  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 at December 31, 2005.

Disregarding the impact of hedges, the average price received for our gas production has historically been approximately $0.30 to $0.50 per Mcf lower than average spot market prices, however, during 2005, widening market differentials caused the difference in our average price received to be approximately $0.90 per Mcf.  Assuming a NYMEX commodity price for 2006 of $8.00 per Mcf of gas, our differential for the average price received for our gas production is expected to be approximately $0.60 to $0.70 per Mcf below the NYMEX Henry Hub index price, including the impact of our basis hedges.  Disregarding the impact of hedges, based on the current price environment, we expect the average price received for our oil production during 2006 to be approximately $1.50 per barrel lower than average spot market prices, as market differentials reduce the average prices received.

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Competition

All phases of the oil and 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 the labor and equipment required to conduct operations.  Our competitors include major oil and gas companies, other independent oil and 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.  The competition for new leases in the Fayetteville Shale play has become especially intense.  Due to our significant leasehold acreage position in Arkansas and our long-time presence and reputation in this area, we believe we will continue to be successful in acquiring new leases in Arkansas.  While improved intrastate and interstate pipeline transportation in Arkansas should increase our access to markets for our gas production, these markets will generally be 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.  

Oil Price Controls and Transportation Rates

Sales of crude oil, condensate and gas liquids are not regulated and are made at negotiated prices.  Effective January 1, 1995, the Federal Energy Regulatory Commission, or the FERC, implemented regulations establishing an indexing system for transportation rates for oil that allowed for an increase in the cost of transporting oil to the purchaser.  The implementation of these regulations has not had a material adverse effect on our results of operations.  

Federal Regulation of Sales and Transportation of Natural Gas 

Historically, the transportation and sale for resale of natural gas in interstate commerce have been regulated pursuant to the Natural Gas Act of 1938, or the NGA, the Natural Gas Policy Act of 1978, or the NGPA, and regulations promulgated thereunder by the FERC.  In 1989, Congress enacted the Natural Gas Wellhead Decontrol Act, or the Decontrol Act.  The Decontrol Act removed all NGA and NGPA price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993 and sales by producers of natural gas can be made at uncontrolled market prices.  With respect to transportation, commencing in 1992, the FERC issued Order No. 636 and subsequent orders (collectively, “Order No. 636”), which require interstate pipelines to provide transportation separately, or “unbundled,” from the pipelines’ sales of gas.  Order No. 636 also requires pipelines to provide open-access transportation on a basis that is equal for all shippers.  Although Order No. 636 does not directly regulate our activities, the FERC has stated that it intends for Order No. 636 to foster increased competition within all phases of the natural gas industry.  Starting in 2000, the FERC issued Order No. 637 and subsequent orders (collectively, “Order No. 637”), which imposed a number of additional reforms designed to enhance competition in natural gas markets.  Among other things, Order No. 637 revised the FERC pricing policy by waiving price ceilings for short-term released capacity for a two-year period, and effected changes in FERC regulations relating to scheduling procedures, capacity segmentation, pipeline penalties, rights of first refusal and information reporting.  Most major aspects of Order No. 637 were upheld on judicial review, though certain issues, such as capacity segmentation and rights of first refusal, were remanded to the FERC, which issued a remand order in October of 2002.  In January of 2004, the FERC denied rehearing of its October 2002 remand order.  Parties appealed such decision to the Court of Appeals for the District of Columbia in late 2004, but no decision has yet been reached.  The implementation of these orders has not had a material adverse effect on our results of operations to date.

Starting on November 25, 2003, FERC issued Order No. 2004 and subsequent orders adopting new Standards of Conduct for transmission providers such as interstate natural gas pipelines.  Every interstate natural gas pipeline was required to file a compliance plan and to be in compliance with the new standards by September 22, 2004.  The primary focus of the new standards was to broaden regulation over certain conduct and interaction between transmission providers and a wider range of affiliates (referred to as “energy affiliates”), including intrastate/Hinshaw natural gas pipelines, processors and gatherers and any company involved in natural gas and electric markets, including gas marketing companies, even if they do not transport natural gas on the affiliated interstate natural gas pipeline.  Most local distribution companies are exempt, however, unless they make off-system sales of natural gas to customers not physically connected to their systems.  The Standards of Conduct mandate, inter alia, separate staffing of interstate natural gas pipelines and their energy affiliates (with certain exemptions for support staff and senior management at the corporate level), strict limitations on communications from an interstate natural gas pipeline to an energy affiliate, and certain disclosure requirements.  The implementation of these orders has not had a material adverse effect on our results of operations to date.

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On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005, or EP Act.  The EP Act is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry.  With respect to regulation of natural gas transportation, the EP Act amends the NGA and the NGPA by increasing the criminal penalties available for violations of each act.  The EP Act also adds a new section to the NGA that provides FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA. Before enactment of the EP Act, FERC was only authorized to impose criminal penalties for violations of the NGA (and criminal or civil penalties for violations of the NGPA).

We cannot predict whether and to what extent FERC’s market reforms and the new energy legislation will survive judicial review and, if so, whether the FERC’s actions 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.

Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts.  The natural gas industry historically has been heavily regulated; therefore, there can be no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.

Natural Gas Distribution

We distribute natural gas to approximately 148,000 customers in northern Arkansas through our subsidiary, Arkansas Western Gas Company.  Our utility is focused on capitalizing on the expanding economy and growth in customers in its Northwest Arkansas service territory.  Approximately 66% of Arkansas Western’s customers are located in the Fayetteville-Springdale-Rogers MSA, which the U.S. Census Bureau named as the 6 ^th fastest growing MSA in the United States in 2001.  In February 2006, the Milken Institute named Northwest Arkansas as the 8 ^th “Best Performing City” in the United States, based upon job creation and local economic growth, attributable in part to the presence of Wal-Mart Stores, Inc., one of the largest public corporations in the world, and other large corporations such as Tyson Foods and J.B. Hunt Transportation.  

Operating income for our natural gas distribution business was $4.9 million in 2005, compared to $8.5 million in 2004 and $6.8 million in 2003.  EBITDA generated by our utility segment was $11.7 million in 2005, compared to $15.2 million in 2004 and $12.9 million in 2003.  The decrease in 2005 operating income and EBITDA resulted primarily from increased operating costs and expenses and warmer than normal weather, which more than offset the rate increase that became effective October 31, 2005.  The increase in 2004 operating income and EBITDA resulted primarily from rate increases implemented in late 2003, partially offset by increased operating costs and expenses.  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 as derived from our audited financial information.  In recent years, Arkansas Western has experienced customer growth of approximately 3% annually in its Northwest Arkansas service territory, while it has experienced no customer growth in its service territory in Northeast Arkansas.  Based on current economic conditions in our service territories, we expect this trend in customer growth to continue.

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Gas Purchases and Supply

Arkansas Western purchases its system gas supply through a competitive bidding process implemented in October 1998, and directly at the wellhead under long-term contracts with flexible pricing provisions.  In 2005, SEECO successfully bid on gas supply packages representing approximately 44% of the requirements for Arkansas Western for 2006, compared to approximately 55% for 2005 and 2004.  The contracts awarded to SEECO expire through 2007.

Arkansas Western also purchases gas under its gas supply packages from unaffiliated suppliers accessed by interstate pipelines.  These purchases are under firm contracts with one-year to two-year terms.  The rates charged by most suppliers include demand components to ensure availability of gas supply and a commodity component that is based on monthly indexed market prices.  The pipeline transportation rates include demand charges to reserve pipeline capacity and commodity charges based on volumes transported.  Less than 4% of the utility’s gas purchases are under take-or-pay contracts.  Arkansas Western believes that it does not have a significant exposure to take-or-pay liabilities resulting from these contracts and expects to be able to continue to satisfactorily manage these contracts.

Arkansas Western has a regulated natural gas storage facility connected to its distribution system in Northwest Arkansas that it utilizes to help meet its peak seasonal demands.  The utility also owns a liquefied natural gas facility and contracts with an interstate pipeline for additional storage capacity to serve its system in the northeastern part of the state.  These contracts involve demand charges based on the maximum deliverability, capacity charges based on the maximum storage quantity, and charges for the quantities injected and withdrawn.

The utility’s rate schedules include a cost of gas rider whereby the actual cost of purchased gas above or below the projected level included in the rates is permitted to be billed or is required to be credited to customers.  The difference between actual costs of purchased gas and gas costs recovered from customers is deferred each month and are billed or credited, as appropriate, to customers in subsequent months.

Arkansas Western enters into hedging activities from time to time with respect to its gas purchases to protect against the inherent price risks of adverse price fluctuations.  Our gas distribution segment hedged 4.2 Bcf of gas purchases in 2005 which had the effect of increasing its total gas supply costs by $2.4 million.  In 2004, our utility hedged 4.5 Bcf of its gas supply which decreased its total gas supply cost by $1.1 million.  In 2003, our utility hedged 4.6 Bcf of its gas supply which decreased its total gas supply cost by $6.1 million.  At December 31, 2005, Arkansas Western had 1.8 Bcf of future gas purchases hedged at an average purchase price of $12.71 per Mcf.  We refer you to “Quantitative and Qualitative Disclosures About Market Risk” and Note 8 to the consolidated financial statements for additional information.

Markets and Customers

Arkansas Western provides natural gas to approximately 131,000 residential, 17,000 commercial, and 170 industrial customers, while also providing gas transportation services to approximately 115 end-use and off-system customers.  Total gas throughput in 2005 was 23.2 Bcf, compared to 25.0 Bcf in 2004 and 2003.  The lower volumes in 2005 primarily resulted from variations in weather and customer conservation brought about by high gas prices in recent years.  Weather in 2005 was 9% warmer than normal and 1% colder than in 2004.  Weather in 2004 was 10% warmer than normal and 9% warmer than in 2003.  

Residential and Commercial .  Approximately 89% of the utility’s revenues in 2005 were from residential and commercial markets.  Residential and commercial customers combined accounted for 57% of total gas throughput for the gas distribution segment in 2005 and 2004, compared to 60% in 2003.  Gas volumes sold to residential customers were 8.1 Bcf in 2005, compared to 8.5 Bcf in 2004 and 9.0 Bcf in 2003.  Gas sold to commercial customers totaled 5.1 Bcf in 2005, 5.7 Bcf in 2004 and 6.1 Bcf in 2003.  The fluctuations in gas volumes sold to both residential and commercial customers were driven primarily by variations in the weather and customer conservation.  The gas heating load is one of the most significant uses of natural gas and is sensitive to outside temperatures.  Sales, therefore, vary throughout the year.  Profits, however, have become less sensitive to fluctuations in temperature as tariffs implemented contain a weather normalization clause to lessen the impact of revenue increases and decreases that might result from weather variations during the winter heating season.

Industrial and End-use Transportation .  Deliveries to Arkansas Western's industrial and end-use transportation customers were 10.0 Bcf in 2005, 9.8 Bcf in 2004 and 9.6 Bcf in 2003.  No industrial customer accounts for more than 10% of Arkansas Western's total throughput.  Arkansas Western offers a transportation service that allows larger business customers to obtain their own gas supplies directly from other suppliers.  Off-system transportation volumes were less than 0.1 Bcf in 2005, 1.0 Bcf in 2004 and 0.3 Bcf in 2003, all to the Ozark Gas Transmission System.  The level of off-system

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deliveries each year generally reflects the changes of on-system demands of our gas distribution systems for our gas production.  As of December 31, 2005, a total of 115 customers used the end-use transportation service.

Competition

Arkansas Western has historically maintained a price advantage over alternative fuels such as electricity, fuel oil, and propane for most applications, enabling it to achieve excellent market penetration levels. However, Arkansas Western has experienced a general trend in recent years toward lower rates of usage among its customers, largely as a result of conservation efforts, as well as increasing competition from alternative fuels that has eroded its price advantage.  Arkansas Western also has the ability to enter into special contracts with larger commercial and industrial customers that contain lower pricing provisions than the approved tariffs. These contracts can be used to meet competition from alternate fuels or threats of bypass and must be approved by the APSC.

Regulation

Arkansas Western’s rates and operations are regulated by the APSC and it operates through municipal franchises that are perpetual by virtue of state law.  These franchises, however, may not be exclusive within a geographic area.  As the regulatory focus of the natural gas industry has shifted from the federal level to the state level, some utilities across the nation are required to unbundle residential sales services from transportation services in an effort to promote greater competition.  There is no such legislation in Arkansas and no regulatory directives related to natural gas are presently pending.  In recent years, there have been efforts by the Arkansas legislature and the APSC concerning the issues of deregulation of the retail sale of electricity and a large-user access program for electric service choice.  Legislation adopted in 2001 for deregulation of the retail sale of electricity was repealed in 2003 and no legislative action has been taken regarding implementing a large-user access program.

In April 2002, the APSC adopted Natural Gas Procurement Plan Rules for utilities. These rules require utilities to take all reasonable and prudent steps necessary to develop a diversified gas supply portfolio. The portfolio should consist of an appropriate combination of different types of gas purchase contracts and/or financial hedging instruments that are designed to yield an optimum balance of reliability, reduced volatility and reasonable price. Utilities are also required to submit on an annual basis their gas supply plan, along with their contracting and/or hedging objectives, to the staff of the APSC for review and determination as to whether it is consistent with these policy principles.

Arkansas Western also purchases gas from unaffiliated producers under take-or-pay contracts. We believe that we do not have significant exposure to liabilities resulting from these contracts and expect to be able to continue to satisfactorily manage our exposure to take-or-pay liabilities.

In October 2005, in response to Arkansas Western’s request for a $9.7 million rate increase, the APSC approved a rate increase totaling $4.6 million annually, exclusive of costs to be recovered through Arkansas Western’s purchase gas adjustment clause. The rate increase was effective for deliveries made to customers on or after October 31, 2005. The request relating to the October 2005 increase assumed a rate of return of 11.5% and a capital structure of 50% debt and 50% equity. The APSC order provided for an allowed return on equity of 9.7% and as assumed capital structure of 54% debt and 46% equity. In its order approving the rate increase, the APSC stated that it would consider in future generic proceedings, certain regulatory changes including a streamlined rate case process, a revenue decoupling mechanism designed to encourage efficiency and conservation, and a performance based methodology designed to allow a variable return on equity adjustment within a reasonable range.

On January 6, 2006, the APSC approved AWG’s Home Weatherization Program, the first customer funded energy efficiency program in Arkansas.  Under this three year pilot program, AWG will assist qualifying customers in making certain home weatherization improvements to their homes to make their homes more energy efficient.  AWG will recover the cost of this program, including any lost margin revenues, from its customers.  

On January 12, 2006, the APSC initiated a Notice of Inquiry regarding a rulemaking for developing and implementing energy efficiency programs.  In this proceeding, the APSC will address all aspects of energy efficiency programs, including, the best programs for Arkansas, cost recovery and incentive mechanisms to encourage utilities to participate in energy efficiency programs.

In September 2003, in response to our request for an $11.0 million rate increase, Arkansas Western received regulatory approval from the APSC of a rate increase totaling $4.1 million annually, exclusive of costs to be recovered through Arkansas Western's purchase gas adjustment clause. The order also entitled Arkansas Western to recover certain

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additional costs totaling $2.3 million through its purchase gas adjustment clause over a two-year period. The rate increase was effective for all customer bills rendered on or after October 1, 2003.

Rate increase requests, which may be filed in the future, will depend on customer growth, increases in operating expenses, and additional investment in property, plant and equipment.

Gas distribution revenues in future years will be impacted by customer growth, customer usage and rate increases allowed by the APSC.  We refer you to “Risk Factors - 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 natural gas distribution business.

Midstream Services

Our Midstream Services segment generates revenue through the marketing of our own gas production and some third-party natural gas and through gathering fees associated with the transportation of natural gas to market.

Gas Marketing

Our gas marketing subsidiary, Southwestern Energy Services Company, was formed in 1996 to better enable us to capture downstream opportunities which arise through marketing and transportation activity.  Our current marketing operations primarily relate to the marketing of our own gas production and some third-party natural gas that is primarily sold to industrial customers connected to our gas distribution systems.  Our operating income from marketing was $5.8 million on revenues of $458.9 million in 2005, compared to $3.2 million on revenues of $315.0 million in 2004, and $2.6 million on revenues of $202.0 million in 2003.  We marketed 61.9 Bcf of natural gas in 2005, compared to 57.0 Bcf in 2004 and 42.7 Bcf in 2003.  The increase in revenues is largely attributable to increased volumes marketed and higher purchased gas costs.  The increase in operating income during 2005 was primarily due to higher marketing margins on natural gas sales caused in large part by the increased volatility of locational market differentials in our core operating areas.  In late 2000, we began marketing less third-party natural gas in an effort to reduce our potential credit risk and concentrated more on marketing our affiliated production.  Of the total volumes marketed, purchases from our E&P subsidiaries accounted for 76% in 2005, 77% in 2004 and 75% in 2003.  Our E&P subsidiaries have accounted for an increasing percentage of our total volumes marketed because of a shift in our focus to marketing our own production in order to reduce our credit risk.

Gas Gathering

In 2004, we formed a new subsidiary, DeSoto Gathering Company, L.L.C., that will be engaging in gathering activities related to the development of our Fayetteville Shale play.  During 2005, we invested approximately $15.8 million related to those activities and had gathering revenues of $1.0 million in 2005.  Gathering revenues and expenses for this segment are expected to continue to grow in the future as gathering systems for our Fayetteville Shale play are constructed to support the development of this play.

Competition

Our gas 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 affiliates of companies with extensive pipeline systems that are used for transportation from producers to end-users.  Other factors affecting competition are cost and availability of alternative fuels, level of consumer demand, and 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.

Transportation and Other

We hold a 25% interest in NOARK, a partnership that owns a 723-mile integrated interstate pipeline system with a total throughput capacity of 330.0 MMcf per day, known as Ozark Gas Transmission System, which became operational November 1, 1998.  On October 31, 2005, Atlas Pipeline Partners, L.P. purchased the remaining 75% interest in NOARK from Enogex, Inc., a wholly-owned subsidiary of OGE Energy Corp., for $165.3 million.

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The average daily throughput for the pipeline was 182.4 MMcf per day in 2005, compared to 155.0 MMcf per day in 2004 and 115.0 MMcf per day in 2003.  The increase in throughput over this time is primarily due to increased gas marketing efforts and widening basis differentials.  Arkansas Western has a transportation contract with Ozark Gas Transmission System for 66.9 MMcf per day of firm capacity that expires in 2014.  Deliveries are made by the pipeline to portions of Arkansas Western's distribution systems and to the interstate pipelines with which it interconnects.  Additionally, Midstream Services has transportation contracts with Ozark Gas Transmission System for a total of 20.0 MMcf per day of firm capacity through 2006.

Our share of NOARK’s results of operations was a pre-tax gain of $1.6 million in 2005, compared to a pre-tax loss of $0.4 million in 2004, and a pre-tax gain of $1.1 million in 2003.  The pre-tax gain in 2005 was primarily due the increase in volumes transported and higher transportation rates collected for those volumes.  The pre-tax loss in 2004 was due primarily to a $0.4 negative adjustment from the operator of the pipeline for prior period allocations of income and expenses to the partners.  In the first quarter of 2003, NOARK sold a 28-mile portion of its pipeline located in Oklahoma that had limited strategic value to the overall system.  Sales proceeds to NOARK were $10.0 million and our share of the proceeds was $2.5 million, resulting in a pre-tax gain to us of $1.3 million recorded in the first quarter of 2003.  The improvements experienced recently in operating results of NOARK result primarily from the ability to collect higher transportation rates on interruptible volumes.   

The Ozark Gas Transmission System primarily competes with one other interstate pipeline to obtain gas supplies for transportation to other markets.  We believe that the Ozark Gas Transmission System will be able to obtain the additional future gas supplies necessary to compete effectively for the transportation of natural gas to end-users and markets served by the interstate pipelines.

The Ozark Gas Transmission System is an interstate pipeline system subject to FERC regulations and FERC-approved tariffs.  The FERC has set the maximum transportation rate of Ozark Gas Transmission System at $0.2867 per dekatherm, plus fuel charges.  

Historically, our other operations have consisted of the activities of our wholly owned subsidiary, A. W. Realty Company, a company with real estate development activities concentrated on tracts of land located near our offices in Fayetteville, Arkansas.  During 2005, we sold approximately 1.6 acres of commercial real estate located in Fayetteville, Arkansas for a pre-tax gain of $0.4 million.  During 2004, we sold 45.5 acres of commercial real estate located in Fayetteville, Arkansas for a pre-tax gain of $5.8 million.  During 2003, we sold 18.5 acres of commercial real estate for a pre-tax gain of $1.7 million, and we sold certain fixed assets for a pre-tax gain of $1.3 million.  These amounts were reflected in “Gas transportation and other” revenues in our income statement.  As of December 31, 2005, A. W. Realty Company owned an interest in approximately 15 acres of undeveloped real estate.

Other Items

Reconciliation of Non-GAAP Measures

EBITDA is defined as net income plus interest, income tax expense, 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, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles 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 is the financial measure calculated and presented in accordance with generally accepted accounting principles that is most directly comparable to EBITDA as defined.  The following table reconciles EBITDA as defined with our net income, as derived from our audited financial information for the years-ended December 31, 2005, 2004 and 2003:

(1)               Revised from prior years' presentation to exclude the amortization of restricted stock issued under our incentive compensation plans.

(2)

Provision for income taxes for 2003 includes the tax benefit associated with the cumulative effect of adoption of accounting principle.

Environmental Matters

Our operations are subject to numerous federal, state and local laws and regulations including the Comprehensive Environmental Response, Compensation and Liability Act, or 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, 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 trend 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.  

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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 crude 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.

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 Environmental Protection Agency, or 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.

Employees

At December 31, 2005, we had 784 total employees, including 358 employed by our natural gas utility, of which 24 are represented under a collective bargaining agreement.  We believe that our relationships with our employees are good.

GLOSSARY OF CERTAIN INDUSTRY TERMS

The definitions set forth below shall apply to the indicated terms as used in this Form 10-K.  All volumes of natural gas referred to herein are stated at the legal pressure base of the state or area where the reserves exist and at 60 degrees Fahrenheit and in most instances are rounded to the nearest major multiple.

“ Bcf ”  One billion cubic feet of gas.

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

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

“ 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 ”  A thermal unit of energy equal to 1,000,000 British thermal units (Btu’s), that is, the equivalent of 1,000 cubic feet of gas having a heating content of 1,000 Btu’s per cubic foot.

“ Development drilling ”  The drilling of a well within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

“ 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 attributable to common stock plus interest, income taxes, depreciation, depletion and amortization.  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 as derived from our audited financial information.

“ Exploratory prospects or locations ”  A location where a well is drilled to find and produce natural gas or oil reserves not classified as proved, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir or to extend a known reservoir.

“ Finding and development costs ”  Costs associated with acquiring and developing proved natural gas and oil reserves which are capitalized pursuant to generally accepted accounting principles, including any capitalized general and administrative expenses.

“ Gross acreage or gross wells ”  The total acres or wells, as the case may be, in which a working interest is owned.

“ Infill drilling ”  Drilling wells in between established producing wells, see also “Downspacing.”

“ Net acres or net wells ”  The sum of the fractional working interests owned in gross acres or gross wells.

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

“ NYMEX ”  The New York Mercantile Exchange.

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

“ 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 gas reserves.

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

“ Proved developed reserves ”  Proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. For additional information, see the SEC’s definition in Rule 4-10(a)(3) of Regulation
S-X, which is available at the SEC’s website, http://www.sec. gov/divisions/corpfin/forms/regsx.htm#gas .

“ Proved reserves ”  The estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. For additional information, see the SEC’s definition in Rule 4-10(a)(2)(i) through (iii) of Regulation S-X, which is available at the SEC’s website, http://www.sec. gov/divisions/corpfin/ forms/regsx.htm#gas .

“ Proved undeveloped reserves ”  Proved reserves 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.  Reserves on undrilled acreage shall be limited to those drilling units that offset productive units and that are reasonably certain of production when drilled. For additional information, see the SEC’s definition in Rule 4-10(a)(4) of Regulation S-X, which is available at the SEC’s website, http://www.sec. gov/divisions/corpfin/forms/regsx.htm#gas .

“ 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.

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

“ Recomplete ” This term refers to the technique of drilling a separate well-bore from all existing casing in order to reach the same reservoir, or redrilling the same well-bore to reach a new reservoir after production from the original reservoir has been abandoned.  

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

“ Step-out well ”  A well drilled adjacent to a proven well but located in an unproven area; a well located a “step out” from proven territory in an effort to determine the boundaries of a producing formation.

“ Undeveloped acreage ”  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

“ Well spacing” The regulation of the number and location of wells over an oil or gas reservoir, as a conservation measure.  Well spacing is normally accomplished by order of the regulatory conservation commission.  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.  

“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 crude oil in the United States.

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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 are not necessarily exhaustive and investors are encouraged to perform their own investigation with respect to us and 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 Operations - Forward-Looking Information.”

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.  The prices for natural gas and oil are subject to wide fluctuation in response to a number of factors, including:

·

relatively minor changes in the supply of and demand for natural gas and oil;

·

market uncertainty;

·

worldwide economic conditions;

·

weather conditions;

·

import prices;

·

political conditions in major oil producing regions, especially the Middle East;

·

actions taken by OPEC;  

·

competition from other sources of energy; and

·

economic, political and regulatory developments.

Price volatility makes it difficult to budget and 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 properties.  Our quarterly 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.  

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

Natural gas and oil prices have recently been at or near their highest historical levels.  A substantial or extended 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:

·

our cash flow would be reduced, decreasing funds available for capital expenditures employed to replace reserves or increase production;

·

certain reserves would no longer be economic to produce, leading to both lower proved reserves and cash flow; and

·

access to other sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable.

Consequently, our revenues and profitability would suffer.

Lower natural gas and oil prices 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.”  This is equal to the present value of estimated future net cash

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flows from proved natural gas and oil reserves, discounted at 10 percent, 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 hedges.  They also require a write-down if the ceiling limit is exceeded, even if prices declined for only a short period of time.  Once a write-down is taken, it cannot be reversed in future periods even if natural gas and oil prices increase.

If natural gas and oil prices fall significantly, a write-down may occur.  Write-downs required by these rules do not impact cash flow from operating activities but do reduce net income and shareholders' equity.

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

We have experienced and expect to continue to experience substantial capital expenditure and working capital needs, particularly as a result of our drilling program. Our planned capital expenditures for 2006 are expected to significantly exceed the net cash generated by our operations.  We expect to borrow under our credit facility to fund capital expenditures that are in excess of our net cash flow and the remaining proceeds of our 2005 equity offering.  Our ability to borrow under our credit facility is subject to certain conditions.  At December 31, 2005, we were in compliance with the borrowing conditions of our credit facility.  If we are not in compliance with the terms of our credit facility in the future, we may not be able to borrow under it to fund our capital expenditures.  We also cannot be certain that other additional 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.

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., an independent petroleum engineering firm.  In conducting its audit, the engineers and geologists of Netherland, Sewell & Associates study our major properties in detail and independently develop reserve estimates.  The estimates of Netherland, Sewell & Associates, Inc. may differ significantly on an individual property basis from our estimates. When, in the aggregate, such differences are within 10%, Netherland, Sewell & Associates, Inc. is generally satisfied that the estimates of proved reserves are reasonable.  

Reserve estimates are 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 the president of our E&P subsidiaries.  Finally, the estimates of our proved reserves together with the audit report of Netherland, Sewell & Associates, Inc. are reviewed by our Board of Directors.  There are numerous uncertainties and risks that are inherent in estimating quantities of natural gas and oil reserves and projecting future rates of production and timing of development expenditures as many factors are beyond our control.  We incorporate many factors and assumptions into our estimates including:

·

expected reservoir characteristics based on geological, geophysical and engineering assessments;

·

future production rates based on historical performance and expected future operating and investment activities;

·

future oil and gas prices and quality and locational differentials; and

·

future development and operating costs.

Although we believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates, our actual results 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, operating and development costs and other factors.  In 2003, reserves were revised downward by 15.5 Bcfe due to poorer-than-expected well performance related to our South Louisiana properties.  In 2004, the reserves were also revised downward by 12.7 Bcfe due primarily to slightly higher decline rates related to some of the wells in our Overton Field in East Texas.  In 2005, our reserves were revised downward by 31.7 Bcfe, primarily due to continued unexpected declines associated with our Gulf Coast properties and minor changes to decline rates for our wells at the Overton Field.  These revisions represented no

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greater than 4% of our total reserve estimates in each of these years, which we believe is indicative of the effectiveness of our internal controls.  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 expenditures and successful drilling operations.  At December 31, 2005, approximately 27% 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 -  Forward-Looking Information” in Item 7A of Part II of this Form 10-K for additional information regarding the uncertainty of reserve estimates.

Our future level of indebtedness may adversely affect operations and limit our growth.

At December 31, 2005, we had long-term indebtedness of $100.0 million, excluding our several guarantee of NOARK’s debt obligation, none of which was indebtedness under our revolving credit facility.  As of February 20, 2006, no bank indebtedness was outstanding under our existing $500 million revolving credit facility.  However, as indicated in the risk factor headed “We may have difficulty financing our planned capital expenditures which could adversely affect our growth” above, we also expect to incur significant additional indebtedness in order to fund a portion of capital expenditures in 2006.  

The terms of the indenture relating to our outstanding senior notes and our revolving credit facility impose significant 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:

·

incurring additional debt, including guarantees of indebtedness;

·

redeeming stock or redeeming debt;

·

making investments;

·

creating liens on our assets; and

·

selling assets.

Our level of indebtedness, and the covenants contained in the agreements governing our debt, could have important consequences for our operations, including:

·

requiring us to dedicate a substantial portion of our cash flow from operations to required payments on debt, thereby reducing the availability of cash flow for working capital, capital expenditures and other general business activities;

·

limiting our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions and general corporate and other activities;

·

limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

·

detracting from our ability to successfully withstand a downturn in our business or the economy generally.

Our ability to comply with the covenants and other restrictions in the agreements governing our debt 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 repayment of outstanding debt.  We may not have sufficient funds to make such repayments.  If we are unable to repay our debt out of cash on hand, we could attempt to refinance such debt, sell assets or repay such debt with the proceeds from an equity offering.  We cannot assure you that we will be able to generate sufficient cash flow to pay the interest on our debt or that future borrowings, equity financings or proceeds from the sale of assets will be available to pay or refinance such debt.  The terms of our debt, including our credit facility and our indentures, may also prohibit us from taking such actions.  Factors that will affect our ability to raise cash through an offering of our capital stock, 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.

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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.  Except to the extent that we acquire additional properties containing proved reserves, conduct successful exploration and development activities, successfully apply new technologies or, through engineering studies, 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 are subject to change.

As of December 31, 2005, we have spud 88 wells relating to our Fayetteville Shale play. The wells were drilled in areas that represent a very small sample of our large acreage position. Our drilling plans with respect to our Fayetteville Shale play are flexible and are dependent upon a number of factors, including the extent to which we can replicate the results of our most successful Fayetteville Shale wells on our other Fayetteville Shale acreage as well as the natural gas and oil commodity price environment.  The determination as to whether we continue to drill prospects in the Fayetteville Shale may depend on any one or more of the following factors:

·

our ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale formation;

·

material changes in natural gas prices;

·

changes in the estimates of costs to drill or complete wells;

·

the extent of our success in drilling and completing horizontal wells;

·

our ability to reduce our exposure to costs and drilling risks;

·

the costs and availability of drilling equipment;

·

success or failure of wells drilled in similar formations or which would use the same production facilities;

·

receipt of additional seismic or other geologic data or reprocessing of existing data;

·

the extent to which we are able to effectively operate the drillings rigs we acquire; or

·

availability and cost of capital.

We continue to gather data about our prospects in the Fayetteville Shale, 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.

We may have difficulty drilling all of the wells that are necessary to hold our Fayetteville Shale acreage before the initial lease terms expire, which could result in the loss of certain leasehold rights.

Approximately 25,737 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.  As discussed above under “Our drilling plans for the Fayetteville Shale play are subject to change,” our ability to drill wells may depend on a number of factors, including certain factors that are beyond our control.  The number of wells we will be required to drill to retain our leasehold rights will be determined by field rules established by the Arkansas Oil and Gas Commission or the AOGC.  Through February 20, 2006, the AOGC has approved field rules for five of our fields in the Fayetteville Shale play, establishing drilling units of 640 acres and well spacing requirements within each drilling unit of 560 feet minimum distance between completions in common sources of supply within the Fayetteville Shale formation, up to a maximum of 25 wells per drilling unit.  There can be no assurance that we will be successful in obtaining the same size drilling unit or the same spacing within each drilling unit in the field rules for our other pilot areas or for our other Fayetteville Shale acreage as a whole.  To the extent that the field rules for our other pilot areas or our other Fayetteville Shale acreage are less favorable, we may not be able to drill the wells required to maintain our leasehold rights for certain of our Fayetteville Shale acreage.

If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost, which could have an adverse effect on our results of operations, financial condition and cash flows.

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As of December 31, 2005, we had invested approximately $15.8 million in our gas gathering operations and we intend to invest approximately $37.5 million in 2006.  Our gas gathering business will largely rely on gas sourced in our Fayetteville Shale play area in Arkansas.  If our Fayetteville Shale drilling program fails to produce a significant supply of natural gas, our investments in our gas gathering operations could be lost, which could have an adverse effect on our results of operations, financial condition and cash flows.

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

We require significant amounts of undeveloped leasehold acreage in order to further our development efforts.  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 are dependent upon the current and future market prices for natural gas and crude oil, costs associated with producing natural gas and crude 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.

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 distribution 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 Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act.  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, and an owner of gas gathering, transmission and distribution systems, 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.  Effective January 1, 2003, companies were required to reflect abandonment costs as a liability on their balance sheets.  We may incur significant abandonment costs in the future which could adversely affect our financial results.

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Natural gas and oil drilling and producing operations involve various risks.

Our operations are subject to all the risks normally incident to the operation and development of natural gas and oil properties and the drilling of natural gas and oil wells, including encountering well blowouts, cratering and explosions, pipe failure, fires, formations with abnormal pressures, uncontrollable flows of oil, natural gas, brine or well fluids, release of contaminants into the environment and other environmental hazards and risks.

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 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.  

We cannot control activities on properties we do not operate.  Failure to fund capital expenditure requirements may result in reduction or forfeiture of our interests in some of our non-operated projects.

We do not operate some of the properties in which we have an interest and we have limited ability to exercise influence over operations for these properties or their associated costs.  Approximately 22% of our gas and oil properties, based on PV10 value, are operated by other companies.  Our dependence on the operator and other working interest owners for these projects and our limited ability to influence operations and associated costs could materially adversely affect the realization of our targeted returns on capital in drilling or acquisition activities and our targeted production growth rate.  The success and timing of drilling, development and exploitation activities on properties operated by others depend on a number of factors that are beyond our control, including the operator's expertise and financial resources, approval of other participants for drilling wells and utilization of technology.  

When we are not the majority owner or operator of a particular natural gas or oil project, we may have no control over the timing or amount of capital expenditures associated with such project.  If we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.

Shortages of oil field equipment, services 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.  There have also been shortages of drilling rigs and other equipment, as demand for rigs and equipment has increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  Higher natural gas and oil prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services.  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 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 recently made significant investments in our drilling rig operations; however, we are still dependent on third party drilling companies.  We also lack experience in owning and operating drilling rigs.

We have recently made significant investments in commencing our drilling rig operations, including commitments to purchase ten drilling rigs and hiring, as of December 31, 2005, 45 new employees for our drilling

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subsidiary, DeSoto Drilling, Inc, or DDI.  We expect DDI to have a total of approximately 275 employees by year end 2006.  The ten drilling rigs will not be sufficient to meet the needs of our drilling program and we will still be dependent upon third party rig providers in order to execute our drilling program in 2006 and beyond.  There can be no assurance that the commencement of our drilling rig operations will not have an adverse effect on our relationships with our existing third party rig providers or our ability to secure third party rigs from other providers.  We may also compete with third party rig providers for qualified personnel, which could adversely affect our relationships with rig providers. If our existing third party rig providers discontinue their relationships with us, we may not be able to secure alternative rigs on a timely basis, or at all.  Even if we are able to secure alternative rigs, there can be no assurance that replacement rigs will be of equivalent quality or that pricing and other terms will be favorable to us.  If we are unable to secure third party rigs or if the terms are not favorable to us, our financial condition and results of operations could be adversely affected.

In addition, we have no prior experience in owning and operating drilling rigs.  We cannot assure you that we will be able to attract and retain qualified field personnel to operate our drilling rigs or to otherwise effectively conduct our drilling operations.  If we are unable to retain qualified personnel or to effectively conduct our drilling operations, our financial and operating results may 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 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.

Our hedging activities may prevent us from benefiting from price increases and may expose us to other risks.

To reduce our exposure to fluctuations in the prices of natural gas and oil, we enter into hedging arrangements with respect to a portion of our expected production.  As of December 31, 2005, we had hedges on approximately 70% to 75% of our targeted 2006 natural gas production and approximately 15% to 20% of our targeted 2006 oil production.  Our price risk management activities reduced revenues by $77.2 million in 2005, $35.6 million in 2004 and $37.4 million in 2003.  To the extent that we engage in hedging activities, we may be prevented from realizing the benefits 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:

·

our production is less than expected;

·

there is a widening of price differentials between delivery points for our production and the delivery point assumed in the hedge arrangement;

·

the counterparties to our futures contracts fail to perform the contracts; or

·

a sudden, unexpected event materially impacts natural gas or oil prices.

In addition, 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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

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